ML092950450

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NUREG-1928, (1:2) Cover-Chpt 3, Section 3.2, Safety Evaluation Report, Related to the License Renewal of Three Mile Island Nuclear Station, Unit 1, Exelon Generation Company, LLC
ML092950450
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Site: Three Mile Island Constellation icon.png
Issue date: 10/31/2009
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NUREG-1928
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{{#Wiki_filter:* US.NRC United States Nuclear Regulatory Commission Protecting People and the Environment NUREG-1928 Safety Evaluation Report Related to the License Renewal of Three Mile Island Nuclear Station, Unit 1 Docket No. 50-289 Exelon Generation Company, LLC I'Office of Nuclear Reactor Regulation United States Nuclear Regulatory Commission Protecting People and the Environment Safety Evaluation Report NUREG-1928 Related to the License Renewal of Three Mile Island Nuclear Station, Unit 1 Docket No. 50-289 Exelon Generation Company, LLC Office of Nuclear Reactor Regulation AVAILABILITY OF REFERENCE MATERIALS IN NRC PUBLICATIONS I NRC Reference Material As of November 1999, you may electronically access NUREG-series publications and other NRC records at NRC's Public Electronic Reading Room at http:ilwww.nrc.qovireading-rm.html. Publicly released records include, to name a few, NUREG-series publications; Federal Register notices;applicant, licensee, and vendor documents and correspondence; NRC correspondence and internal memoranda; bulletins and information notices;inspection and investigative reports; licensee event reports; and Commission papers and their attachments. NRC publications in the NUREG series, NRC regulations, and Title 10, Energy, in the Code of Federal Regulations may also be purchased from one of these two sources.1. The Superintendent of Documents U.S. Govemment Printing Office Mail Stop SSOP Washington, DC 20402-0001 Intemet: bookstore.gpo.gov Telephone: 202-512-1800 Fax: 202-512-2250

2. The National Technical Information Service Springfield, VA 22161-0002 www.ntis.gov 1-800-553-6847 or, locally, 703-605-6000 A single copy of each NRC draft report for comment is available free, to the extent of supply, upon written request as follows: Address: U.S. Nuclear Regulatory Commission Office of Administration

.Reproduction and Mail Services Branch Washington, DC 20555-0001 E-mail: DISTRIBUTION(anrc.qov Facsimile: 301-415-2289 Some publications in the NUREG series that are posted at NRC's Web site address httn:t/www.nrc-oovlreadino-rmldoc-collectionsfnureos Non-NRC Reference Material Documents available from public and special technical libraries include all open literature items, such as books, journal articles, and transactions, Federal Register notices, Federal and State legislation, and congressional reports. Such documents as theses, dissertations, foreign reports and translations, and non-NRC conference proceedings may be purchased from their sponsoring organization. Copies of industry codes and standards used in a substantive manner in the NRC regulatory process are maintained at-The NRC Technical LibraryTwo White Flint North 11545 Rockville Pike Rockville, MD 20852-2738These standards are available in the library for reference use by the public. Codes and standards are usually copyrighted ahd may be purchased from the originating organization or, if they are American National Standards, from-American National Standards Institute 11 West 42nd Street New York, NY 10036-8002 www.ansi.org 212-642-4900 Legally binding regulatory requirements are stated only in laws; NRC regulations; licenses, including technical specifications; or orders, not in NUREG-series publications. The views expressed in contractor-prepared publications in this series are not necessarily those of the NRC.The NUREG series comprises (1) technical and administrative reports and books prepared by the staff (NUREG-XXXX) or agency contractors (NUREG/CR-XXXX), (2) proceedings of conferences (NUREG/CP-XXXX), (3) reports resulting from international agreements (NUREG/IA-XXXX), (4)brochures (NUREG/BR-XXXX), and (5) compilations of legal decisions and orders of the Commission and Atomic and Safety Licensing Boards and of Directors' decisions under Section 2.206 of NRC's regulations (NUREG-0750). are updated periodically and may differ from the last printed version. Although references to material found on a Web site bear the date the material was accessed, the material available on the date cited may subsequently be removed from the site.AVAILABILITY OF REFERENCE MATERIALS IN NRC PUBLICATIONS NRC Reference Material As of November 1999, you may electronically access NUREG-series publications and other NRC records at NRC's Public Electronic Reading Room at http://www.nrc.gov/reading-rm.html. Publicly released records include, to name a few, NUREG-series publications; Federal Register notices; applicant, licensee, and vendor documents and correspondence; NRC correspondence and internal memoranda; bulletins and information notices; inspection and investigative reports; licensee event reports; and Commission papers and their attachments. NRC publications in the NUREG series, NRC regulations, and Titlfj 10, Energy, in the Code of Federal Regulations may also be purchased from one of these two sources. 1. The Superintendent of Documents U.S. Govemment Printing Office Mail Stop SSOP Washington, DC 20402-0001 Intemet: bookstore.gpo.gov Telephone: 202-512-1800 Fax: 202-512-2250

2. The National Technical Information Service Springfield, VA 22161-0002 www.ntis.gov 1-800-553-6847 or, locally, 703-605-6000 A single copy of each NRC draft report for comment is available free, to the extent of supply, upon written request as follows: Address: U.S. Nuclear Regulatory Commission Office of Administration Reproduction and Mail Services Branch Washington, DC 20555-0001 E-mail: DISTRIBUTION@nrc.gov Facsimile:

301-415-2289 Some publications in the NUREG series that are posted at NRC's Web site address http://www.nrc.gov/reading-rm/doc-collectionsfnuregs are updated periodically and may differ from the last printed version. Although references to material found on a Web site bear the date the material was accessed, the material available on the date cited may subsequently be removed from the site. Non-NRC Reference Material Documents available from public and special technical libraries include all open literature items, such as books, journal articles, and transactions, Federal Register notices, Federal and State legislation, and congressional reports. Such documents as theses, dissertations, foreign reports and translations, and non-NRC conference proceedings may be purchased from their sponsoring organization. Copies of industry codes and standards used in a substantive manner in the NRC regulatory process are maintained at-The NRC Technical Library Two White Flint North 11545 Rockville Pike Rockville, MD 20852-2738 These standards are available in the library for reference use by the 'public. Codes and standards are usually copyrighted and may be purchased from the originating organizatidn or, if they are American National Standards, American National Standards Institute 11 West 42 nd Street New York, NY 10036-8002 www.ansi.org 212-642-4900 Legally binding regulatory requirements are stated only in laws; NRC regulations; licenses, including technical specifications; or orders, not in NUREG-series publications. The views expressed in contractor-prepared publications in this series are not necessarily those of the NRC. The NUREG series comprises (1) technical and administrative reports and books prepared by the staff (NUREG-XXXX) or agency contractors (NUREG/CR-XXXX), (2) proceedings of conferences (NUREG/CP-XXXX), (3) reports resulting from intemational agreements (NUREGIIA-XXXX), (4) brochures (NUREG/BR-XXXX), and (5) compilations of legal decisions and orders of the Commission and Atomic and Safety Licensing Boards and of Directors' decisions under Section 2.206 of NRC's regulations I(NUREG-0750).

  1. U.S.NRC United States Nuclear Regulatory Commission Protecting People and the Environment NUREG-1928 Safety Evaluation Report Related to the License Renewal of Three Mile Island Nuclear Station, Unit 1 Docket No. 50-289 Exelon Generation Company, LLC Manuscript Completed:

October 2009 Date Published: October 2009 Office of Nuclear Reactor Regulation United States Nuclear Regulatory Commission Protecting People and the Environment Safety Evaluation Report Related to the License Renewal of Three Mile Island Nuclear Station, Unit 1 Docket No. 50-289 Exelon Generation Company, LLC Manuscript Completed: October 2009 Date Published: October 2009 Office of Nuclear Reactor Regulation NUREG-1928

ABSTRACT This safety evaluation report (SER) documents the technical review of the Three Mile Island Nuclear Station, Unit 1, (TMI-1) license renewal application (LRA) by the U.S. Nuclear Regulatory Commission (NRC) staff (the staff). By letter dated January 08, 2008 AmerGen Energy Company, LLC (AmerGen 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." AmerGen requests renewal of the TMI-1 operating license (Facility Operating License Number DPR-50) for a period of 20 years beyond the current expiration at midnight on April 14, 2014.TMI-1 is located approximately 10 miles southeast of Harrisburg, Pennsylvania. The staff issued the construction permit for TMI-1 on May 18, 1968, and the operating license on April 19, 1974.The plant's nuclear steam supply system consists of a pressurized water reactor (PWR-DRYAMB) with a lowered loop. The nuclear steam supply system was supplied by Babcox &Wilcox. The balance of the plant was originally designed by Gilbert Associates and constructed by United Engineers and Constructors (UE&C). TMI-1 operates at a licensed power output of 2,568 megawatt-thermal, with a gross electrical output of approximately 852 megawatt-electric. This SER presents the status of the staffs review of information submitted through June 29, 2009, the cutoff date for consideration in this SER. The staff did not identify any open items that must be resolved before any final determination is reached by the staff on the LRA.iii ABSTRACT This safety evaluation report (SER) documents the technical review of the Three Mile Island Nuclear Station, Unit 1, (TMI-1) license renewal application (LRA) by the U.S. Nuclear Regulatory Commission (NRC) staff (the staff). By letter dated January 08, 2008 AmerGen Energy Company, LLC (AmerGen 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." AmerGen requests renewal of the TMI-1 operating license (Facility Operating License Number DPR-50) for a period of 20 years beyond the current expiration at midnight on April 14, 2014. TMI-1 is located approximately 10 miles southeast of Harrisburg, Pennsylvania. The staff issued the construction permit for TMI-1 on May 18, 1968, and the operating license on April 19, 1974. The plant's nuclear steam supply system consists of a pressurized water reactor DRYAMB) with a lowered loop. The nuclear steam supply system was supplied by Babcox & Wilcox. The balance of the plant was originally designed by Gilbert Associates and constructed by United Engineers and Constructors (UE&C). TMI-1 operates at a licensed power output of 2,568 megawatt-thermal, with a gross electrical output of approximately 852 megawatt-electric. This SER presents the status of the staffs review of information submitted through June 29, 2009, the cutoff date for consideration in this SER. The staff did not identify any open items that must be resolved before any final determination is reached by the staff on the LRA. iii

TABLE OF CONTENTS ABSTRACT. i TABLE O F CONTENTS ............................................................................................................................ v LIST O F TABLES .................................................................................................................................... xii ABBREVIATIONS .................................................................................................................................... xiii INTRO DUCTIO N AND G ENERA L DISCUSSIO N ................................................................................. 1-1 1.1 Introduction .......................................................................................................................... 1-1 1.2 License Renewal Background ............................................................................................. 1-3 1.2.1 Safety Review ...................................................................................................................... 1-3 1.2.2 Environm ental Review ......................................................................................................... 1-5 1.3 Principal Review Matters ...................................................................................................... 1-5 1.4 Interim Staff G uidance ......................................................................................................... 1-7 1.5 Sum m ary of O pen Item s ...................................................................................................... 1-7 1.6 Sum m ary of Confirm atory Item s .......................................................................................... 1-8 1.7 Sum m ary of Proposed License Conditions .......................................................................... 1-8 STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW .................... 2-1 2.1 Scoping and Screening M ethodology .................................................................................. 2-1 2.1.1 Introduction .......................................................................................................................... 2-1 2.1.2 Sum m ary of Technical Inform ation in the Application .......................................................... 2-1 2.1.3 Scoping and Screening Program Review ............................................................................ 2-2 2.1.3.1 Implementing Procedures and Documentation Sources Used for Scoping and Screening ....................................................................................................................... 2-3 2.1.3.2 Quality Controls Applied to LRA Developm ent .............................................................. 2-5 2.1.3.3 Training .......................................................................................................................... 2-6 2.1.3.4 Scoping and Screening Program Review Conclusion ....................... 2-6 2.1.4 Plant Systems, Structures, and Components Scoping Methodology ................................. 2-7 2.1.4.1 Application of the Scoping Criteria in 10 CFR 54.4(a)(1) .............................................. 2-7 2.1.4.2 Application of the Scoping Criteria in 10 CFR 54.4(a)(2) ..................... 2-9 2.1.4.3 Application of the Scoping Criteria in 10 CFR 54.4(a)(3) ............................................ 2-14 2.1.4.4 Plant-Level Scoping of System s and Structures ......................................................... 2-17 2.1.4.5 M echanical Com ponent Scoping ................................................................................. 2-20 2.1.4.6 Structural Scoping ....................................................................................................... 2-21 2.1.4.7 Electrical Com ponent Scoping .................................................................................... 2-22 2.1.4.8 Scoping M ethodology Conclusion ............................................................................... 2-23 2.1.5 Screening M ethodology ..................................................................................................... 2-23 2.1.5.1 General Screening M ethodology ................................................................................ 2-23 2.1.5.2 M echanical Com ponent Screening ............................................................................. 2-25 2.1.5.3 Structural Com ponent Screening ................................................................................ 2-26 2.1.5.4 Electrical Com ponent Screening .................................. ............................................... 2-27 2.1.5.5 Screening M ethodology Conclusion ............................................................................ 2-29 2.1.6 Sum m ary of Evaluation Findings ....................................................................................... 2-29 2.2 Plant-Level Scoping Results .............................................................................................. 2-29 2.2.1 Introduction ......................................................................................................................... 2-292.2.2 Sum m ary of Technical Inform ation in the Application ........................................................ 2-29 2.2.3 Staff Evaluation ................................................................................................................... 2-30 2.2.4 Conclusion ......................................................................................................................... 2-30 V TABLE OF CONTENTS ABSTRACT .........................................................................................................................

.....................

iii TABLE OF CONTENTS .................................................................................. '" ....................................... v LIST OF TABLES .................................................................................................................................... xii ABBREViATIONS .................................................................................................................................... xiii INTRODUCTION AND GENERAL DiSCUSSION ................................................................................. 1-1 1.1 Introduction .......................................................................................................................... 1-1 1 .2 License Renewal Background ............................................................................................. 1-3 1.2.1 Safety Review ...................................................................................................................... 1-3 1 .2.2 Environmental Review ......................................................................................................... 1-5 1.3 Principal Review Matters ...................................................................................................... 1-5 1.4 Interim Staff Guidance ......................................................................................................... 1-7 1 .5 Summary of Open Items ...................................................................................................... 1-7 1.6 Summary of Confirmatory Items .......................................................................................... 1-8 1.7 Summary of Proposed License Conditions .......................................................................... 1-8 STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REViEW .................... 2-1 2.1 Scoping and Screening Methodology ............ , ..................................................................... 2-1 2.1.1 Introduction .......................................................................................................................... 2-1 2.1.2 Summary of Technical Information in the Application .......................................................... 2-1 2.1.3 Scoping and Screening Program Review ............................................................................ 2-2 2.1.3.1 Implementing Procedures and Documentation Sources Used for Scoping and Screening ....................................................................................................................... 2-3 2.1.3.2 Quality Controls Applied to LRA Development... ........................................................... 2-5 2.1.3.3 Training .......................................................................................................................... 2-6 2.1.3.4 Scoping and Screening Program Review Conclusion ................................................... 2-6 2.1.4 Plant Systems, Structures, and Components Scoping Methodology .. : ............................... 2-7 2.1.4.1 Application of the Scoping Criteria in 10 CFR 54.4(a)(1) .............................................. 2-7 2.1.4.2 Application of the Scoping Criteria in 10 CFR 54.4(a)(2) .............................................. 2-9 2.1.4.3' Application of the Scoping Criteria in 10 CFR 54.4(a)(3) ............................................ 2-14 2.1.4.4 Plant-Level Scoping of Systems and Structures ......................................................... 2-17 2.1.4.5 Mechanical Component Scoping ................................................................................. 2-20 2.1.4.6 Structural Scoping ....................................................................................................... 2-21 2.1.4.7 Electrical Component Scoping .................................................................................... 2-22 2.1.4.8 Scoping Methodology Conclusion ............................................................................... 2-23 2.1.5 Screening Methodology ..................................................................................................... 2-23 2.1.5.1 General Screening Methodology ................................................................................. 2-23 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 ................................................................................. 2-27 2.1.5.5 Screening Methodology Conclusion ............................................................................ 2-29 2.1.6 Summary of Evaluation Findings ....................................................................................... 2-29 2.2 Plant-Level Scoping Results .............................................................................................. 2-29 2.2.1 Introduction ........................................................................................................................ 2-29 2.2.2 Summary of Technical Information in the Application ..............................

.........................

2-29 2.2.3 Staff Evaluation ................................................................................................................... 2-30 2.2.4 Conclusion ......................................................................................................................... 2-30 v

2.3 Scoping

and Screening Results: Mechanical System s ...................................................... 2-30 2.3.1 Reactor Vessel, Internals, and Reactor Coolant System ................................................... 2-32 2.3.1.1 Reactor Coolant System .............................................................................................. 2-32 2.3.1.2 Reactor Vessel ............................................................................................................ 2-33 2.3.1.3 Reactor Vessel Internals ............................................................................................. 2-33 2.3.1.4 Steam Generators ....................................................................................................... 2-34 2.3.2 Engineered Safety Features .......................................... 2-34 2.3.2.1 Core Flooding System ................................................................................................ ý 2-34 2.3.2.2 Decay Heat Rem oval System ..................................................................................... 2-35 2.3.2.3 Makeup and Purification System (High Pressure Injection) ....................................... 2-35 2.3.2.4 Prim ary Containm ent Heating and Ventilation System ..............................................

  • 2-36 2.3.2.5 Reactor Building Spray System ...................................................................................

2-37 2.3.2.6 Reactor Building Sum p and Drain System .................................................................. 2-37 2.3.3 Auxiliary System s ............................................................................................................... 2-38 2.3.3.1 Auxiliary and Fuel Handling Building Ventilation System ............................................ 2-39 2.3.3.2 Auxiliary Steam System ............................................................................................... 2-39 2.3.3.3 Circulating W ater System ........................................................................................... 2-40 2.3.3.4 Closed Cycle Cooling W ater System .......................................................................... 2-40 2.3.3.5 Containment Isolation System .................................................................................... ý' 2-43 2.3.3.6 Control Building Ventilation System ............................ .....2-43 2.3.3.7 Cranes and Hoists ...................................................................................................... 2-44 2.3.3.8 Diesel Generator Building Ventilation System ............................................................. 2-45 2.3.3.9 Emergency Diesel Generators and Auxiliary Systems ................................................ 2-45 2.3.3.10 Fire Protection System ................................................................................................ 2-47 2.3.3.11 Fuel Handling and Fuel Storage System ................................... 2-52 2.3.3.12 Fuel Oil System .......................................................................................................... 2-52 2.3.3.13 Hydrogen Monitoring System ..................................................................................... 2-53 2.3.3.14 Instrument and Control Air System ............................................................................. 2-53 2.3.3.15 Intake Screen and Pum p House Ventilation System .................................................. 2-56 2.3.3.16 Intermediate Building Ventilation System ................................................................... 2-56 2.3.3.17 Liquid and Gas Sam pling System ............................................................................... 2-57 2.3.3.18 Miscellaneous Floor and Equipm ent Drains System ................................................... 2-63 2.3.3.19 Open Cycle Cooling W ater System ............................................................................ 2-64 2.3.3.20 Radiation Monitoring System ...................................................................................... 2-67 2.3.3.21 Radwaste System ........................................................................................................ 2-69 2.3.3.22 Service Building Chilled W ater System ....................................................................... 2-70 2.3.3.23 Spent Fuel Cooling System ......................................................................................... 2-71 2.3.3.24 Station Blackout and UPS Diesel Generator System .................................................. 2-7.1 2.3.3.25 W ater Treatm ent and Distribution System .................................................................. 2-72 2.3.4 Steam and Power Conversion System s ............................................................................ 2-73 2.3.4.1 Condensate System .................................................................................................... 2-73 2.3.4.2 Condensers and Air Rem oval System ........................................................................ 2-74 2.3.4.3 Emergency Feedwater System .................................................................................. 2-75 2.3.4.4 Extraction Steam System ........................................................................................... 2-77 2.3.4.5 Feedwater System ....................................................................................................... 2-78 2.3.4.6 Main Generator and Auxiliary System s ....................................................................... 2-79 2.3.4.7 Main Steam System ................................................................................................... 2-79 2.3.4.8 Steam Turbine and Auxiliary System s ........................................................................ 2-80 2.4 Scoping and Screening Results: Structures ...................................................................... 2-82 2.4.1 Air Intake Structure ............................................................................................................ 2-83 2.4.1.1 Sum mary of Technical Information in the Application ................................................. 2-83 2.4.1.2 Conclusion ................................................................................................................... 2-84 2.4.2 Auxiliary Building ................................................................................................................ 2-84 vi 2.3 Scoping and Screening Results: Mechanical Systems ...................................................... 2-30 2.3.1 Reactor Vessel, Internals, and Reactor Coolant System ................................................... 2-32 2.3.1.1 Reactor Coolant System ................................................ .............................................. 2-32 2.3.1.2 Reactor Vessel .......... .................................................................................................. 2-33 2.3.1.3 Reactor Vessel Internals ............................................................................................. 2-33 2.3.1.4 Steam Generators ....................................................................................................... 2-34 2.3.2 Engineered Safety Features .............................................................................................. 2-34 2.3.2.1 Core Flooding System ................................................................................................

2-34 2.3.2.2 Decay Heat Removal System ......................................................................................

2-35 2.3.2.3 Makeup and Purification System (High Pressure Injection) ...............

........................

2-35 2.3.2.4 Primary Containment Heating and Ventilation System ............................................... 2-36 2.3.2.5 Reactor Building Spray System ................................................................................... 2-37 2.3.2.6 Reactor Building Sump and Drain System .................................................................. 2-37 2.3.3 Auxiliary Systems ..................................................................................................... .......... 2-38 2.3.3.1 Auxiliary and Fuel Handling Building Ventilation System ............................................ 2-39 2.3.3.2 Auxiliary Steam System ............................................................................................... ' 2-39 2.3.3.3 Circulating Water System ...................................................... ..................................... i 2-40 2.3.3.4 Closed Cycle Cooling Water System .......................................................................... 2-40 2.3.3.5 Containment Isolation System ................................................................................... .!I 2-43 2.3.3.6 Control Building Ventilation System ............................................................................ 2-43 2.3.3.7 Cranes and Hoists ....................................................................................................... 2-44 2.3.3.8 Diesel Generator Building Ventilation System ................................................ ............. 2-45 2.3.3.9 Emergency Diesel Generators and Auxiliary Systems ................................................ 2-45 2.3.3.10 Fire Protection System ................................................................................................ 2-47 2.3.3.11 Fuel Handling and Fuel Storage System ..................................................................... 2-52 2.3.3.12 Fuel Oil System ........................................................................................................... 2-52 2.3.3.13 Hydrogen Monitoring System ...................................................................................... 2-53 2.3.3.14 Instrument and Control Air System ............................................................................. 2-53 2.3.3.15 Intake Screen and Pump House Ventilation System .................................................. 2-56 2.3.3.16 Intermediate Building Ventilation System ...................................................................

2-56 2.3.3.17 Liquid and Gas Sampling System ...............................................................................

2-57 2.3.3.18 Miscellaneous Floor and Equipment Drains System ................................................... 2-63 2.3.3.19 Open Cycle Cooling Water System ............................................................................ , 2-64 2.3.3.20 Radiation Monitoring System ................................................ ...................................... i 2-67 2.3.3.21 Radwaste System ........................................................................................................ 2-69 2.3.3.22 Service Building Chilled Water System ...................................................... ................. 2-70 2.3.3.23 Spent Fuel Cooling System ...................................................... ................................... 2-71 2.3.3.24 Station Blackout and UPS Diesel Generator System .................................................. 2-71 2.3.3.25 Water Treatment and Distribution System .................................................................. 2-72 2.3.4 Steam and Power Conversion Systems ...................................................... ...................... 2-73 2.3.4.1 Condensate System ...................................................... .............................................. 2-73 2.3.4.2 Condensers and Air Removal System ...................................................... .................. 2-74 2.3.4.3 Emergency Feedwater System ..................................................................................

2-75 2.3.4.4 Extraction Steam System ...........................................................................................
' 2-77 2.3.4.5 Feedwater System .......................................................................................................

2-78 2.3.4.6 Main Generator and Auxiliary Systems ...................................................... ................. 2-79 2.3.4.7 Main Steam System ...................................................... .............................................. 2-79 2.3.4.8 Steam Turbine and Auxiliary Systems ........................................................................ 2-80 2.4 Scoping and Screening Results: Structures ...................................................................... 2-82 2.4.1 Air Intake Structure ................................ ........................................................................... 2-83 2.4.1.1 Summary of Technical Information in the Application ................................................. 2-83 2.4.1.2 Conclusion ................................................................................................................... 2-84 2.4.2 Auxiliary Building ................................................................................................................ 2-84 vi 2.4.2.1 Summary of Technical Information in the Application.................................... 2-84 2.4.2.2 Staff Evaluation.............................................................................. 2-85 2.4.2.3 Conclusion ................................................................................... 2-86 2.4.3 Circulating Water Pump House ................................................................. 2-86 2.4.3.1 Summary of Technical Information in the Application.................................... 2-862.4.3.2 Conclusion ................................................................................... 2-86 2.4.4 Control Building................................................................................... 2-87 2.4.4.1 Summary of Technical Information in the Application.................................... 2-87 2.4.4.2 Staff Evaluation.............................................................................. 2-87.2.4.4.3 Conclusion ................................................................................... 2-88 2.4.5 Diesel Generator Building ....................................................................... 2-88 2.4.5.1 Summary of Technical Information in the Application.................................... 2-88 2.4.5.2 Staff Evaluation.............................................................................. 2-88 2.4.5.3 Conclusion.................................................................................... 2-89 2.4.6 Dike/Flood Control System...................................................................... 2-89 2.4.6.1 Summary of Technical Information in the Application.................................... 2-89 2.4.6.2 Staff Evaluation .............................................................................. 2-902.4.6.3 Conclusion ................................................................................... 2-91 2.4.7 Fuel Handling Building........................................................................... 2-91 2.4.7.1 Summary of Technical Information in the Application.................................... 2-91 2.4.7.2 Conclusion.................................................................................... 2-92 2.4.8 Intake Screen and Pump House................................................................ 2-92 2.4.8.1 Summary of Technical Information in the Application.................................... 2-92 2.4.8.2 Conclusion.................................................................................... 2-92 2.4.9 Intermediate Building ............................................................................ 2-93 2.4.9.1 Summary of Technical Information in the Application.................................... 2-93 2.4.9.2 Conclusion.................................................................................... 2-93 2.4.10 Mechanical Draft Cooling Tower Structures ................................................... 2-93 2.4.10.1 Summary of Technical Information in the Application.................................... 2-93 2.4.10.2 Staff Evaluation .............................................................................. 2-94 2.4.10.3 Conclusion.................................................................................... 2-94 2.4.11 Miscellaneous Yard Structures ................................................................. 2-95 2.4.11.1 Summary of Technical Information in the Application.................................... 2-95 2.4.11 .2 Conclusion.................................................................................... 2-952.4.12 Natural Draft Cooling Towers.................................................................... 2-96 2.4.12.1 Summary of Technical Information in the Application.................................... 2-96 2.4.12.2 Staff Evaluation.............................................................................. 2-96 2.4.12.3 Conclusion.................................................................................... 2-97 2.4.13 Structural Commodities .......................................................................... 2-97 2.4.13.1 Summary of Technical Information in the Application.................................... 2-97 2.4.13.2 Conclusion.................................................................................... 2-98 2.4.14 Reactor Building ................... ............................................................... 2-98 2.4.14.1 Summary of Technical Information in the Application.................................... 2-98 2.4.14.2 Staff Evaluation.............................................................................. 2-99 2.4.14.3 Conclusion.................................................................................... 2-99 2.4.15 SBO Diesel Generator Building ............................................................... 2-100 2.4.1 5.1 Summary of Technical Information in the Application .................................. 2-100 2.4.15.2 Conclusion .................................................................................. 2-1002.4.16 Service Building................................................................................. 2-100 2.4.16.1 Summary of Technical Information in the Application .................................. 2-100 2.4.16.2 Staff Evaluation ............................................................................ 2-100 2.4.16.3 Conclusion .................................................................................. 2-101 2.4.17 Component Supports Commodity Group ..................................................... 2-102 Vii 2.4.2.1 Summary of Technical Information in the Application ................................................. 2-84 2.4.2.2 Staff Evaluation .......................... , ................................................................................ 2-85 2.4.2.3 Conclusion ................................................................................................................... 2-86 2.4.3 Circulating Water Pump House .......................................................................................... 2-86 2.4.3.1 Summary of Technical Information in the Application ................................................. 2-86 2.4.3.2 Conclusion ....................................................................... '" ......................................... 2-86 2.4.4 Control Building .................................................................................................................. 2-87 2.4.4.1 Summary of Technical 'nformation in the Application ................................................. 2-87 2.4.4.2 Staff Evaluation ........................................................................................................... 2-87 , 2.4.4.3 Conclusion ................................................................................................................... 2-88 2.4.5 Diesel Generator Building .................................................................................................. 2-88 2.4.5.1 Summary of Technical Information in the Application ................................................. 2-88 2.4.5.2 Staff Evaluation ........................................................................................................... 2-88 2.4.5.3 Conclusion .................................................................................................................... 2-89 2.4.6 Dike/Flood Control System ................................................................................................ 2-89 2.4.6.1 Summary of Technical Information in the Application ................................................. 2-89 2.4.6.2 Staff Evaluation .......................................................... , ................................................. 2-90 2.4.6.3 Conclusion ................................................................................................................... 2-91 2.4.7 Fuel Handling Building ....................................................................................................... 2-91 2.4.7.1 Summary of Technical Information in the Application ................................................. 2-91 2.4.7.2 Conclusion ................................................................. .................................................. 2-92 2.4.8 Intake Screen and Pump House ........................................................................................ 2-92 2.4.8.1 Summary of Technical Information in the Application ................................................. 2-92 2.4.8.2 Conclusion ................................................................................................................... 2-92 2.4.9 Intermediate Building ......................................................................................................... 2-93 2.4.9.1 Summary of Technical Information in the Application ................................................. 2-93 2.4.9.2 Conclusion ................................................................................................................... 2-93 2.4.10 Mechanical Draft Cooling Tower Structures ...................................................................... 2-93 2.4.10.1 Summary of Technical Information in the Application ................................................. 2-93 2.4.10.2 Staff Evaluation ................................................... ' ........................................................ 2-94 2.4.10.3 Conclusion ................................................................................................................... 2-94 2.4.11 Miscellaneous Yard Structures .......................................................................................... 2-95 2.4.11.1 Summary of Technical Information in the Application ................................................. 2-95 2.4.11.2 Conclusion ............. ...................................................................................................... 2-95 2.4.12 Natural Draft Cooling Towers ............................................................................................. 2-96 2.4.12.1 Summary of Technical Information in the Application ................................................. 2-96 2.4.12.2 Staff Evaluation ........................................................................................................... 2-96 2.4.12.3 Conclusion ................................................................................................................... 2-97 2.4.13 Structural Commodities ...................................................................................................... 2-97 2.4.13.1 Summary of Technical Information in the Application ................................................. 2-97 2.4.13.2 Conclusion ...........................................................................................................

....... 2-98 2.4.14 Reactor Building .................................. , ...........................................................................

... 2-98 2.4.14.1 Summary of Technical Information in the Application ................................................. 2-98 2.4.14.2 Staff Evaluation ................................................

..........

................................................ 2-99 2.4.14.3 Conclusion ................................................................................................................... 2-99 2.4.15 SBO Diesel Generator Building ....................................................................................... 2-100 2.4.15.1 Summary of Technical Information in the Application ............................................... 2-100 2.4.15.2 Conclusion ................................................................................................................. 2-100 2.4.16 Service Building ................................................................ ............................................... 2-100 2.4.16.1 Summary of Technical Information in the Application ............................................... 2-100 2.4.16.2 Staff Evaluation ......................................................................................................... 2-100 2.4.16.3 Conclusion ................................................................................................................. 2-101 2.4.17 Component Supports Commodity Group ......................................................................... 2-102 vii 2.4.17.1 Sum m ary of Technical Information in the Application, .............................................. 2-102 2.4.17.2 Conclusion ................................................................................................................. 2-102 2.4.18 Substation structures ....................................................................................................... 2-102 2.4.18.1 Sum m ary of Technical Inform ation in the Application ............................................... 2-102 2.4.18.2 Conclusion ................................................................................................................. 2-103 2.4.19 Turbine Building ............................................................................................................... 2-103 2.4.19.1 Sum m ary of Technical Information in the Application ............................................... 2-103 2.4.19.2 Staff Evaluation ......................................................................................................... 2-104 2.4.19.3 Conclusion ................................................................................................................. 2-104 2.4.20 UPS Diesel Building ......................................................................................................... 2-104 2.4.20.1 Sum m ary of Technical Information in the Application ............................................... 2-104 2.4.20.2 Conclusion ................................................................................................................. 2-105 2.5 Scoping and Screening Results: Electrical Systems/Commodity Groups ....................... 2-105 2.5.1 Electrical and Instrum entation and Controls System s ..................................................... 2-107 2.5.1.1 Sum m ary of Technical Inform ation in the Application ............................................... 2-107 2.5.1.2 Staff Evaluation ......................................................................................................... 2-108 2.5.1.3 Conclusion ................................................................................................................. 2-109 2.6 Conclusion for Scoping and Screening ............................................................................ 2-109 AG ING MANAGEM ENT REVIEW RESULTS ....................................................................................... 3-1 3.0 Applicant's Use of the Generic Aging Lessons Learned Report .................................................... 3-1 3.0.1 Format of the License Renewal Application ........................................................................... 3-2 3.0.1.1 Overview of Table ls ....................................................................................................... 3-2 3.0.1.2 Overview of Table 2s ....................................................................................................... 3-3 3.0.2 Staff's Review Process ...................................................................................................

  • ....... 3-4 3.0.2.1 Review of AMPs ....................................................................................................

3-4 3.0.2.2 Review of AM R Results ................................................................................................... 3-5 3.0.2.3 UFSAR Supplem ent ........................................................................................................ 3-6 3.0.2.4 Docum entation and Docum ents Reviewed ..................................................................... 3-6 3.0.3 Aging Management Programs ............................................................................................... 3-6 3.0.3.1 AMPs That Are Consistent with the GALL Report .......................................................... 3-9 3.0.3.2 AMPS That Are Consistent with the GALL Report with Exceptions or Enhancements 3-32 3.0.3.3 AMPs That Are Not Consistent with or Not Addressed in the GALL Report ............... 3-126 3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs ............. 3-133 3.0.4.1 Sum m ary of Technical Information inApplication ....................................................... 3-133 3.0.4.2 Staff Evaluation ........................................................................................................... 3-133 3.0.4.3 Conclusion ................................................................................................................... 3-134 3.1 Aging Management of Reactor Coolant System .............................................................. 3-135 3.1.1 Sum mary of Technical Information in the Application ...................................................... 3-135 3.1.2 Staff Evaluation ....................................................................................................... 3-135 3.1.2.1 AM R Results That Are Consistent with the GALL Report ......................................... 3-152 3.1.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recom m ended ..................................................................................... 3-160 3.1.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report. 3-178 3.1.3 Conclusion ....................................................................................................................... 3-180 3.2 Aging Management of Engineered Safety Features (ESF) ............................................. 3-182 3.2.1 Sum mary of Technical Information in the Application ...................................................... 3-182 3.2.2 Staff Evaluation ................................................................................................................ 3-182 3.2.2.1 AMR Results That Are Consistent with the GALL Report ......................................... 3-191 3.2.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation Is Recom m ended .................................................................................... 3-205 3.2.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report. 3-216 3.2.3 Conclusion ....................................................................................................................... 3-224 viii 2.4.17.1 Summary of Technical Information in the Application , .............................................. 2-102 2.4.17.2 Conclusion ................................................................................................................. 2-102 2.4.18 Substation structures ....................................................................................................... 2-102 2.4.18.1 Summary of Technical Information in the Application ............................................... 2-102 2.4.18.2 Conclusion ................................................................................................................. 2-103 2.4.19 Turbine Building ............................................................................................................... 2-103 2.4.19.1 Summary of Technical Information in the Application ............................................... 2-103 2.4.19.2 Staff Evaluation ......................................................................................................... 2-104 2.4.19.3 Conclusion ................................................................................................................. 2-104 2.4.20 UPS Diesel Building ......................................................................................................... 2-104 2.4.20.1 Summary of Technical Information in the Application ............................................... 2-104 2.4.20.2 Conclusion ................................................................................................................. 2-105 2.5 Scoping and Screening Results: Electrical Systems/Commodity Groups ....................... 2-105 2.5.1 Electrical and Instrumentation and Controls Systems ..................................................... 2-107 2.5.1.1 Summary of Technical Information in the Application ............................................... 2-107 2.5.1 .2 Staff Evaluation ......................................................................................................... 2-108 2.5.1 .3 Conclusion ................................................................................................................. 2-109 2.6 Conclusion for Scoping and Screening ............................................................................ AGING MANAGEMENT REVIEW RESULTS ....................................................................................

.. 3-1 3.0 Applicant's Use of the Generic Aging Lessons Learned Report .....................................................

3-1 3.0.1 Format of the License Renewal Application ........................................................................... 3-2 3.0.1.1 Overview of Table 1. s ....................................................................................................... 3-2 3.0.1.2 Overview of Table 2s ....................................................................................................... 3-3 3.0.2 Staff's Review Process ......................................................................................................... ' .. 3-4 3.0;2.1 Review of AMPs .. : ......................................................................................................... ' .. 3-4 3.0.2.2 Review of AMR Results ................................................................................................. ,.. 3-5 3.0.2.3 UFSAR Supplement ........................................................................................................ 3-6 3.0.2.4 Documentation and Documents Reviewed ..................................................................... 3-6 3.0.3 Aging Management Programs ............................................................................................... 3.0.3.1 AMPs That Are Consistent with the GALL Report .......................................................... 3-9 3.0.3.2 AMPS That Are Consistent with the GALL Report with Exceptions or Enhancements' 3-32 3.0.3.3 AMPs That Are Not Consistent with or Not Addressed in the GALL Report ............... 3-126 3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs ............. 3-133 3.0.4.1 Summary of Technical Information in Application ....................................................... 3-133 3.0.4.2 Staff Evaluation .................................................................................................... : ...... 3-133 3.0.4.3 . Conclusion ...................................................................................................

...............

3-134 3.1 Aging Management of Reactor Coolant System .............................................................. 3-135 3.1.1 Summary of Technical lriformation in the Application ...................................................... 3-135 3.1.2 Staff Evaluation ................................................................................................................ 3-135 3.1.2.1 AMR Results That Are Consistent with the GALL Report ......................................... 3-152 3.1.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended ..................................................................................... 3-160 3.1.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report. 3-178 3.1.3 Conclusion ....................................................................................................................... 3-180 3.2 Aging Management of Engineered Safety Features (ESF) ............................................. 3-182 3.2.1 Summary of Technical Information in the Application ...................................................... 3-182 3.2.2 Staff Evaluation ................................................................................................................ 3-182 3.2.2.1 AMR Results That Are Consistent with the GALL Report ......................................... 3-191 3.2.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further ' Evaluation Is Recommended ..................................................................................... 3-205 3.2.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report. 3-216 3.2.3 Conclusion ........................................................................................................................ 3-224 viii

3.3 Aging

M anagement of Auxiliary Systems .......................................................................... 3-225 3.3.1 Summary of Technical Information in theApplication ................. 3-225 3.3.2 Staff Evaluation ..................................................................... .............................................. 3-226 3.3.2.1 AMR Results That Are Consistent with the GALL Report ................. 3-242 383.2.2 AMR Results That Are Consistent with the GALLReport, :for Which Furher Evaluation is Recomm ended ............................................................................... 3-266 3.3.2.3 AMR Results ThatAre:Not Consistent with or Not Addressed inthe GALL Report. 3-302 3.3.3 Conclusion............................................................... .. ....... 3-330 3.4 Aging Management of Steam and.Power Conversion System...... ................ 3-331 3.4.1 Summary of Technical Information in the Application ...... .. ...... 3-331 3.4.2 StaffEvialuation,.:.,.... .............. ....., ..... .......... ..... ........ .............. ... .,3-331 3.4.2.1 AMR Results That Are'Consistent with theGALL Repo't..................3-338, 3.4.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended....... ............................. 3-344 34.2.3 AMR Results That Are Not Consistent with or Not Addressed In the GALL Report, 3-359 3.4.3 Conclusion .............. ............. .................................... 3-371 3.5 Aging Management of Containments, Structures, and Component Supports ...... ....... 3-372*3.5.1 Summary of Technical Information in the Application ..... ........................ ............... 3-372 3.5.2 Staff Evaluation............. ............ * ........... .........3-372 3.5.2.1 AMR Results That Are Consistent with the GALL Report....... .................. 3.-386 3.5.2.2 AMR-Results That Are Consistent with the GALL Report, for Which Further Evaluation Is Recommended ........................ ............ 3-391 3.5.2.3` AMR Results That Are Not Consistent with or Not Addressed.in the GALL Report. 3-414 3.5.3 Conclusion ................... ............................................. 3-440: 3.6 Aging Managemert of Electrical Commodity.Group. ........ ............... ,..;....... ....... 3-441 3.6.1 Summary ofTehnical Information in the Application ......... ....................... ........ ... 3441.6.2 Staff EvalUation. ................ ............. ........................... 3-441 3.6.2.1 AMR Results That Are Consistent With the GALL Report ............... ,. I........ 3-444 3.6.2.2 AMR Results That Are Consistent with:the GALL Report, for Which Further Evaluation is Recommended.... .. ................... ........... I.. .. ........ 3-446 3.6.2.3 AMR Results That Are Not Consistent with or Not'Addressed in the GALL Report.... 3-450.ý3.6.3. Conclusion... ................................................. 3-452 3.7 COnclusion for Aging Management Review Results ....... ................................. 3-4531 TIME-LIMITED AGING ANALYSES ................... ........................... ......... .. .............. 471 4.1 Identification of Tlme-Limlted Aging Analyses .................. ....................................... 4-1 4.1.1 Summary of:Technical Informatlon:in the Application ......................... 4-1 4.1.2 Staff Evaluation ............................................. ...................................... 4-2 4.1.3: Conclusion ... ... ............... ............... .................... 4-3 4.2 Neutron Embrittlement of the Reactor Vessel and Internals.... ................... 4-3 4.2.1 Neutron Fluence Analysis. ...... 0 ................................................... 44 4.2.1.1 Summary of Technical Information in theApplication ................ 4............... .......4* .................... ..... .... ... .. .... ... ...4.2.1.2 Staff Evaluation............................. ............... .4 4.2.1.3 UFSAR Supplement ........................ ......... 6 ...................... .4-7:4.2.1 .4 Conclusion.. .................................................. 4-7 4.2.2 Charpy Upper-Shelf Energy for Beltline Plates.and Forgings. ...i.,...................... 4-7 4.2.2.1 Summary~of Technical Information in the Application ...................... 4-7 4.2.2.2 Staff Evaluation ........ .................................................................................... 4-8 4.2.2.3 UFSAR Supplement...........I.. ..... .... ................... ........ 4-9 4.2.2:4 Conclusion .......... ............. .............................. 4-94.2.3 Charpy Upper-Shelf Energy for Beltline Welds (Equivalent Margins:Analysis)................ 4-9 4.2.3.1 Summary of Technical Information in the Application.... ....... ................ I..................... 4-9 4.2.3.2 Staff Evaluation ..... .............. ............ .... ..................................................... 4-10 ix 3.3 Aging Managemen(o.fAuxiliary Systems ....... , ..... ....... , ................ ,., ............ , .... .. , ........ 3-225 3;3.1 Suml11ary o.f Technicallnformatio.nin .. , ...... ............... , ... , ........ " ......... , .. *3-225. 3.3,2' Staff*Evaluatio l1., ..... , ...........................

...........................
......................................... ..........
  • 3-226. 3,3.2.1 AMRResults ThatAreConsistenl with

....................................... 3-242 3.3.2.2 . AMR' Results ThafAreConsistentwiththe GALL Report; ;forWhich Further . Evaluation is Recommended .....................................

................................................

3.3.2.3 AMR Results That Are NotColJsisteritwithor NotAddressedin]he GALL R.eport. 3-302 3.3.3' . Conclusion .. "," ......................*....... ............... .............

, , *...*. ;,., ......*..*..
, ..... ........ ; .*
*.. 3-330 3,4 Aging.

System. , ..... ; ......... , ....... ;.'" , ....... ,;.3-331 3A.1Summary ofTechniC:allnf()rmationin the .... ; .... ;. ;, ..........

*. ;.,." ' *. ;; ...........
.. '," 3-331 '3.4,2. Staff:Evaluation\.;

.*.... ;; .... i .......... , ** ;;;'., .............. '; ...... ; ***** ;;' ........ ,.;. ,;. ;.;; ** ; **** " ..... , ***. ; ** ; .. ; ** ; .* ;., .**** , ** ;*3-331 AMR ResllltsTpat ...... u ... :: ** , ..... .. ;:,.;:.; ** ; ***** ;. :3-338 3.4.2.2 .. AMRResults ThatAreConsistenfwith the GALl., Report,forWhich Further Evaluation is ReccmU11ended

.....

.. i **..**. **** ****** ....... , .* : .* , ** 0; ** ;: ******** : ***** , ** 3-344 Results TllatAre NotConsistelJt with or Not Addre!?sed IntheGALL Report

  • 3,.359 3A.3* Conclusion

.:.:,,, .. , ... , ...... ,., ......*....... , .. , .*. .. ;;: .. : ............

..... ; ...........
.. .*. .... ; ..*... ; ............
... ;.3-371 . 3.5 . Aging Management of Containments;.

Structures; and Co.mponent Supports ...... , ...... ;. *. 3-372 3.5.1 Suri'lrharyof Technicalll'lformation intlwApplication., ........ ; ..................

..... ;., .. ;. .. ;..; ..... , 3-3 72 Staff Evaluatioh

....* .. : ... ;; ... ;; .. ;;" ....... ,., .. ; ........................

.. ; ... ; ...... ;; ............

,.; ........ : .. ; ... ,' .. ,3-372* 1 '" AMRRes'ultsThat Are Consistent with the GALL Report ...... ;; ..............

... ; ... ' .... i ....

3.5.2.2 AMRRe,sults That AteConslsteritiNiththeGALL Report, for Which Further Evaluation Is Recommended ..............................

...... ; ....
.: .. ; ..... , .. ; ..... ; ... ; ..... , ............

3,5.2.3. AMR ResUlts ThatAre Not Consistent with or Not Addressed in the GALL Report; 3-414 3.5.3 Conclusion

...... ;' ..... ; ......*
...............
....................
.. ,';: .... ;; .. * ... i .. ;' ....* :*.;; ...... ; ....... : ........ : .* :.; ....... 3-440,* 3:6' Aging' Managemenfof ElectricaIColT1inodityGr6up.;

.0; *** ;. ; ****** ,.;; *********

.;; .........

,.;;. ;: *** ;: .........

. 3-441 '. 3.6.1 Informationih the Application
............
.
.... ;.; ..... ; .........
............
.. 3-441 Staff' Evaluation

............. .... ;.; ...... ; ............ ,. ;.; ...... ; ............... , ..........

....................
................

3-441 3.6.2.1AMRResults ThatAreCbnsistentwith the GALL Report ... ;.;.;..; .........

. ....... ;.,.
.. ; ...... 3-444 3.6.2.2 AMR Results That Are Consistent with the GALL Report, forWhich Further' Evaluation is Recommended

....... ; .....................................

  • ...........................

3.6.2;3AMR Results That Are Not.Corisistent With or NotAddressedintheGALL Report ... 3-450 3.6.3' ConClusion .............

....... * ..* ....... ; ....*. , ............

' ....................

.. ; .... ;.; ....... ; ..............................
.. 3-452 3.1' Conclusion for AgingManagementReview Results ........................ , .......
.; .... , ..........................

3-453 TIME-LIMITED,AGING ANALySES ........................................................ , ...................

., .... ............ , ....... 4-:1 4:1 Idenlifjcatjon*ofTlme-:IJmlledAgingAnalyses
  • .. ; .* , .. ..........................................................

4"-1. 4.1.1 Summary of Technical Informatlon;n the Applicatiori ..... , ..............

.....................................

4 .. 1 4.1.2. .Staff Evaluation: .......................

  • .... , ................................
  • ................
.................... , ................... 4.1.3. Conclusion

................ ............ , .......................................... , .......... , ............................ , ............. 4-3. 4.2 Neutron .Embrittlementof the. ReactorVesseland ............................................... 4-3 .4.2.1 Neutron* .. , ............. , ....... , .....................

................ , ..*. ; ................. , ........... , ....... , .... 4-4 4.2.1.1 '$Urnmary ofTechn'ical,fnforrnation.in the Application

... , ........ , ......... , ................................ 4 '4:2.1 .. 2 .Staff Evaluation ... : .... , ......................................

............................................................. , ........... , 4 .. 4 . 4.2.1.3..UFSAR*

Supplement ................... , .................................................................. , .... , .............. . '4.2.1:.4' . Conclusion ...... : ....... , ......................... ".'.' ............. , ........ : ............. , ................................... , ......... 4-7 4.2.2 Charpy \Jpper-Shelfi:nergy for .......... ..................................... 4-7 4.2.2.1 Summary;of Technicallnformatiorl.in the ...................... HO ............ , ................... 4-7 4.2.2.:2 .. Slaff Ev;aluation .......................................................... , ........... , ... , ...... , ................................ 4;2.2.3:' UFSAR .. , ...................... , ... , ................ , ..................................

...........
...... ;., ...... 4-9 4,2.2.
4*

Conclusion ............... , .................... , .... , ...... .'.* .... ;; .. : ........ : ........ :.: ...**. ; .............. ,; ............. ,.: ................ 4-9 Charpy Upper-Shelf Energyfor Beltline Welds (Eql,jivalent Margins Analysis) ..................... 4-9 4.2.3.1 $ummaryofTechnicallnformation in the Application ..................................................... 4-9 4.2.3 .. 2' Staff Evaluation .................. , .......................

........................
.......... , .................................

4-10* ix 4.2.3.3 UFSAR Supplement ...................................................................................................... 4-11 4.2.3.4 Conclusion .....................................

...............................................................................

4-11 4.2.4 Pressurized Thermal Shock Limits (RTPTS) for Reactor Vessel Materials Due to Neutron Em brittlem ent ....................................................................................................... 4-11 4.2.4.1 Summ ary of Technical Information in the Application ................................................... 4-11 4.2.4.2 Staff Evaluation ............................................................................................................. 4-12 4.2.4.3 UFSAR Supplem ent ...................................................................................................... 4-13 4.2.4.4 Conclusion ..................................................................................................................... 4-13 4.2.5 Reactor Vessel Operating Pressure -Temperature Limits, Including Adjusted Reference ý!Temperatures and Low Temperature Overpressure Protection Limits .............................. 4-13 4.2.5.1 Summary of Technical Information in the Application ................................................... 4-13 4.2.5.2 Staff Evaluation ............................................................................................................. 4-14 4.2.5.3 UFSAR Supplem ent ..................................................................................................... 4-14 4.2.5.4 Conclusion ..................................................................................................................... 4-144.2.6 Neutron Em brittlement of Reactor Vessel Internals ............................................................. 4-14 4.2.6.1 Sum mary of Technical Inform ation in the Application ................................................... 4-14 4.2.6.2 Staff Evaluation ............................................................................................................. 4-15 4.2.6.3 UFSAR Supplem ent ...................................................................................................... 4-15 4.2.6.4 Conclusion ..................................................................................................................... 4-15 4.3 Metal Fatigue of Piping and Com ponents .................................................................................... 4-15 4.3.1 Evaluation of Fatigue in ASME Class 1 and USAS B31.7 Piping and Components ........... 4-16 4.3.1.1 Summ ary of Technical Inform ation in the Application ................................................... 4-16 4.3.1.2 Staff Evaluation ............................................................................................................. 4-17 4.3.1.3 UFSAR Supplem ent ...................................................................................................... 4-18 4.3.1.4 Conclusion ..................................................................................................................... 4-18 4.3.2 Evaluation of Reactor Water Environmental Effects on Fatigue Life of Piping and Com ponents (Generic Safety Issue 190) ........................................................................... 4-18 4.3.2.1 Summ ary of Technical Inform ation in the Application ................................................... 4-18 4.3.2.2 Staff Evaluation ............................................................................................................. 4-20 4.3.2.3 UFSAR Supplem ent ...................................................................................................... 4-27 4.3.2.4 Conclusion ..................................................................................................................... 4-27 4.3.3 ASME Class 2 and 3 and USAS B31.1 Piping and Component Fatigue Analysis .............. 4-27 4.3.3.1 Summ ary of Technical Inform ation in the Application ................................................... 4-27 4.3.3.2 Staff Evaluation ............................................................................................................. 4-27 4.3.3.3 UFSAR Supplement .................................................................................................... 4-28 4.3.3.4 Conclusion ..................................................................................................................... 4-28 4.3.4 Reactor Vessels Internals Fatigue Analysis ......................................................................... 4-28 4.3.4.1 Sum mary of Technical Inform ation in the Application .................................................. 4-28 4.3.4.2 Staff Evaluation ............................................................................................................. 4-28 4.3.4.3 UFSAR Supplem ent ...................................................................................................... 4-29 4.3.4.4 Conclusion ..................................................................................................................... 4-29 4.3.5 Reactor Vessel Internals Flow-Induced Vibration Analysis .................................................. 4-29 4.3.5.1 Sum mary of Technical Inform ation in the Application ................................................... 4-29 4.3.5.2 Staff Evaluation ............................................................................................................. 4-30 4.3.5.3 UFSAR Supplem ent ...................................................................................................... 4-31 4.3.5.4 Conclusion ..................................................................................................................... 4-31 4.3.6 Underclad Cracking Evaluation For Reactor Vessel ............................................................ 4-31 4.3.6.1 Summary of Technical Inform ation in the Application ................................................... 4-31 4.3.6.2 Staff Evaluation ............................................................................................................. 4-32 4.3.6.3 UFSAR Supplement ....................................................................................................... 4-32 4.3.6.4 Conclusion ....................................................................................................................... 4-32 4.3.7 Reactor Coolant Pump Motor Flywheel Fatigue Crack Growth Analysis ............................. 4-32 4.3.7.1 Sum mary of Technical Inform ation in the Application ................................................... 4-32 x 4.2.3.3 UFSAR Supplement ...................................................................................................... 4-11 4.2.3.4 Conclusion .....................................

...............................................................................

4-11 4.2.4 Pressurized Thermal Shock Limits (RTPTS) for Reactor Vessel Materials Due to Neutron Embrittlement ....................................................................................................... 4-11 4.2.4.1 Summary of Technical Information in the Application ................................................... 4-11 4.2.4.2 Staff Evaluation ............................................................................................................. 4-12 4.2.4.3 UFSAR Supplement ...................................................................................................... 4-13 4.2.4.4 Conclusion ..................................................................................................................... 4-13 4.2.5 Reactor Vessel Operating Pressure -Temperature Limits, Including Adjusted Reference" Temperatures and Low Temperature Overpressure Protection Limits .............................. 4-13 4.2.5.1 Summary of Technical Information in the Application ................................................... 4-13 4.2.5.2 Staff Evaluation ............................................................................................................. 4-14 4.2.5.3 UFSAR Supplement ...................................................................................................... 4-14 4.2.5.4 Conclusion ..................................................................................................................... 4-14 4.2.6 Neutron Embrittlement of Reactor Vessel Internals ............................................................. 4-14 4.2.6.1 Summary of Technical Information in the Application ................................................... 4-14 4.2.6.2 Staff Evaluation ............................................................................................................. '4-15 4.2.6.3 UFSAR Supplement ...................................................................................................... 4-15 4.2.6.4 Conclusion ..................................................................................................................... 4-15 4.3 Metal Fatigue of Piping and Components .................................................................................... 4-15 4.3.1 Evaluation of Fatigue in ASME Class 1 and USAS 831.7 Piping and Components ........... 4-16 4.3.1.1 Summary of Technical Information in the Application ................................................... 4-16 4.3.1.2 Staff Evaluation ............................................................................................................. 4-17 4.3.1.3 UFSAR Supplement ...................................................................................................... 4-18 4.3.1.4 Conclusion ..................................................................................................................... 4-18 4.3.2 Evaluation of Reactor Water Environmental Effects on Fatigue Life of Piping and Components (Generic Safety Issue 190) ........................................................................... 4-18 4.3.2.1 Summary of Technical Information in the Application ................................................... 4-18 4.3.2.2 Staff Evaluation ............................................................................................................. 4-20 4.3.2.3 UFSAR Supplement ...................................................................................................... 4-27 4.3.2.4 Conclusion ..................................................................................................................... 4-27 4.3.3 ASME Class 2 and 3 and USAS 831.1 Piping and Component Fatigue Analysis .............. 4-27 4.3.3.1 Summary of Technical Information in the Application ................................................... 4-27 4.3.3.2 Staff Evaluation ............................................................................................................. 4-27 4.3.3.3 UFSAR Supplement ........................... .......................................................................... 4-28 4.3.3.4 Conclusion ..................................................................................................................... 4-28 4.3.4 Reactor Vessels Internals Fatigue Analysis ......................................................................... 4-28 4.3.4.1 Summary of Technical Information in the Application ................................................... 4-28 4.3.4.2 Staff Evaluation ............................................................................................................

4-28 4.3.4.3 UFSAR Supplement

...................................................................................................... 4-29 4.3.4.4 Conclusion ..................................................................................................................... 4-29 4.3.5 Reactor Vessel Internals Flow-Induced Vibration Analysis .................................................. 4-29 4.3.5.1 Summary of Technical Information in the Application ................................................... 4-29 4.3.5.2 Staff Evaluation ............................................................................................................. 4-30 4.3.5.3 UFSAR Supplement ...................................................................................................... 4-31 4.3.5.4 Conclusion ..................................................................................................................... 4-31 4.3.6 Underclad Cracking Evaluation For Reactor Vessel ............................................................ 4-31 4.3.6.1 Summary of Technical Information in the Application ................................................... 4-31 4.3.6.2 Staff Evaluation ............................................................................................................. 4-32 4.3.6.3 UFSAR Supplement ..................................................................................................... ., 4-32 4.3.6.4 Conclusion ..................................................................................................................... ' 4-32 4.3.7 Reactor Coolant Pump Motor Flywheel Fatigue Crack Growth Analysis ............................. 4-32 4.3.7.1 Summary of Technical Information in the Application ................................................... 4-32 x 4.3.7.2 Staff Evaluation ............................................................................................................. 4-33 4.3.7.3 UFSAR Supplem ent ...................................................................................................... 4-33 4.3.7.4 Conclusion .............................................. I ...................................................................... 4-344.4 Leak-Before-Break Analysis of Prim ary System Piping ............................................................... 4-34 4.4.1 Sum m ary of Technical Inform ation in the Application .......................................................... 4-34 4.4.2 Staff Evaluation .................................................................................................................... 4-35 4.4.2.1 Fatigue Crack Growth Analysis ..................................................................................... 4-354.4.2.2 Therm al Em brittlem ent of Cast Austenitic Stainliess Steel ............................................ 4-38 4.4.2.3 Im pact of PW SCC on LBB Piping ................................................................................. 4-40 4.4.2.4 Im pact of Power Uprate on LBB Piping ......................................................................... 4-42 4.4.3 UFSAR Supplem ent ............................................................................................................. 4-42 4.4.4 Conclusion ............................................................................................................................ 4-43 4.5 Fuel Transfer Tube Bellows Design Cycles ................................................................................. 4-43 4.5.1 Sum m ary of Technical Inform ation in the Application .......................... ................................ 4-434.5.2 Staff Evaluation .................................................................................................................... 4-44 4.5.3 UFSAR Supplem ent ............................................................................................................. 4-444.5.4 Conclusion ............................................................................................................................ 4-44 4.6 Crane Load Cycle Lim its .............................................................................................................. 4-44 4.6.1 Sum m ary of Technical Inform ation in the Application .......................................................... 4-44 4.6.2 Staff Evaluation .................................................................................................................... 4-4 5 4.6.3 UFSAR Supplem ent ............................................................................................................ 4-454.6.4 Conclusion .................................................... ...... 4-45 4.7 Loss of Prestress in Concrete Containm ent Tendons .................................................................. 4-46 4.7.1 Sum m ary of Technical Inform ation in the Application .......................................................... 4-464.7.2 Staff Evaluation .................................................................................................................... 4-4 6 4.7.3 UFSAR Supplem ent ............................................................................................................. 4-474.7.4 Conclusion ............................................................................................................................ 4-47 4.8 Environmental Qualification of Electrical Equipment .............................. 4-48 4.8.1 Sum m ary of Technical Inform ation in the Application .......................................................... 4-48 4.8.2 Staff Evaluation .................................................................................................................... 4-48 4.8.3 UFSAR Supplem ent ............................................................................................................. 4-49 4.8.4 Conclusion ........................................................................................................................... 4-49 4.9 Conclusion .................................................................................................................................... 4-49 REVIEW BY THE ADVISORY COMMITTEE ON REACTOR SAFEGUARDS ..................................... 5-1 CONCLUSION ........................................................................................................................................ 6-1 APPENDIX A: Com m itm ents For License Renewal Of TM I-1 ......................................................... A-1 APPENDIX B: Chronology .................................................................................................................... B-1 APPENDIX C: Principal Contributors .............................................................................................. C-1 APPENDIX D: References .................................................................................................................... D-1 xi 4.3.7.2 Staff Evaluation ............................................................................................................. 4-33 4.3.7.3 UFSAR Supplement .................................................................................................... ,. 4-33 4.3.7.4 Conclusion ..................................................................................................................... 4-34 4.4 Leak-Before-Break Analysis of Primary System Piping ............................. '" ............................... 4-34 4.4.1 Summary of Technical Information in the Application .......................................................... 4-34 4.4.2 Staff Evaluation .................................................................................................................... 4-35 4.4.2.1 Fatigue Crack Growth Analysis ..................................................................................... 4-35 4.4.2.2 Thermal Embrittlement of Cast Austenitic Stainless Steel. ........................................... 4-38 4.4.2.3 Impact of PWSCC on LBB Piping ................................................................................. 4-40 4.4.2.4 Impact of Power Uprate on LBB Piping ................. '" ..................................................... 4-42 4.4.3 UFSAR Supplement ............................................................................................................. 4-42 4.4.4 Conclusion ............................................................................................................................ 4-43 4.5 Fuel Transfer Tube Bellows Design Cycles ........................ '" ...................................................... 4-43 4.5.1 Summary of Technical Information in the Application .......................................................... 4-43 4.5.2 Staff Evaluation .................................................................................................................... 4-44 4.5.3 UFSAR Supplement ............................................................................................................. 4-44 4.5.4 Conclusion ............................................................................................................................ 4-44 4.6 Crane Load Cycle Limits .............................................................................................................. 4-44 4.6.1 Summary of Technical Information in the Application .......................................................... 4-44 4.6.2 Staff Evaluation .................................................................................................................... 4-45 4.6.3 UFSAR Supplement .......................... , .................................................................................. 4-45 4.6.4 Conclusion ............................................................

...............................................................

4-45 4.7 Loss of Prestress in Concrete Containment Tendons .................................................................. 4-46 4.7.1 Summary of Technical Information in the Application .......................................................... 4-46 4.7.2 Staff Evaluation .................................................................... , ............................................... 4-46 4.7.3 UFSAR Supplement ............................................................................................................. 4-47 4.7.4 Conclusion ............................................................................................................................ 4-47 4.8 Environmental Qualification of Electrical Equipment... ................................................................. 4-48 4.8.1 Summary of Technical Information in the Application .......................................................... 4-48 4.8.2 Staff Evaluation .................................................................................................................... 4-48 4.8.3 UFSAR Supplement ............................................................................................................. 4-49 4.8.4 Conclusion .............................

..............................................................................................

4-49 4.9 Conclusion .................................................................................................................................... 4-49 REVIEW BY THE ADVISORY COMMITTEE ON REACTOR SAFEGUARDS ..................................... 5-1 CONCLUSiON ......................................................................................................................

................

6-1 APPENDIX A: Commitments For License Renewal Of TMI-1 .............................................................. A .. 1 APPENDIX B: Chronology ..................................................................................................................... B-1 APPENDIX C: Principal Contributors .......................................... , ......................................................... C-1 APPENDIX D: References .................................................................................................................... D-1 xi LIST OF TABLES Table 1.4ý1 Current and Proposed Interim Staff Guidance .... w ......... ................. .................. 1-7 Table 3.0.3-1 TMI-I Aging.ManagementPrgrams .... .... .... I.................. Table 3.1-. Staff Evaluation for Reactor Vessel, Reactor Vessel Internals, and Reactor Coolant:System Components in the GALL Report.; ..... ....... .............. 3136 Table 3.2-1 Staff Evaluation for Engineered Safety Features System Components in the GALL Report ............................... .............. ............ 3-183 Table 3.3-1 Staff Evaluation for Auxiliary System Components in the GALL Report ..........

. 3-226 Table 3.4-1 Staff Evaluation for Steam and Power Conversion Systems Components in the GALL Report ........ ........................

............................ ............................ ......... 3-332 Table 3.5-1 Staff Evaluation for Containments; Structures, and Component Supports in the GALL Report .... .................. ................ ............... ...... 3-374 Table 3.6-11 Staff Evaluation for Electrical and Instrumentation and Controls in the GALL Report....3-442 xii LlSTOFTASLES. CurrenfandProposed**lnterirn Stiff Guidance ... " ; ..... .. ; .. .. ; ...* ; .. ;, ,.,;;, .*... ;,,,,.; .......... u ...... 1 Table 3.0j .... 1 AgingManagementPr09rams; .... ........... .. , .... ,:: .. :,' ..... ;;, .... , .. '" *... ....* , ......... 3-6 Table 3J Evaluatioh for-Reactor Vessel, . Reactor Vessel Internals; and Reactor Coolant SyStem Components in the GALL Report .......... , ........ ; .* ; ....*. ;; .................... , ..... ;;; ... Table Staff Evaluation for Engineered SafetyFeaturesSysteni ... . in the GALL*Report; .... ;* .........................

................... , ........ , ................
...... ; ..................

u .. , ... , ............... 3-183 Staff Evaluation for Auxiliary System Components in the GALL Report .. ; ........ ; .........

.3-226 Table 3.4.-1 Staff Evaluation for Steam and Pbwer Conversion Systems Components

.. in**the *GALL Report ...............

...........
, ......................

......**.* .......................... ......*...

.....*.......
....*....

Table 3.5-.1 Staff Evaluation for Containments; Structures, and Component Supports in *the*GALL Report*.*.

...........
............
.... ; ..........
... ; ..... ; ......... ........ ;., ................
....
....... ;,;; .........
.; .....*......

Staff Evaluation for Electrical andlnstrumentatioriarid Controls in the GALL Report .... 3-442 xii ABBREVIATIONS AC alternating current ACI American Concrete Institute ACRS Advisory Committee on Reactor Safeguards ADAMS Agencywide Document Access and Management System ADV atmospheric dump valve AERM aging effect requiring management AFW auxiliary feedwater AISC American Institute of Steel Construction AMP aging management program AMR aging management review ANSI American National Standards Institute ART adjusted reference temperature ASME American Society of Mechanical Engineers ASTM American Society for Testing and Materials ATWS anticipated transient without scram B&PV Boiler and Pressure Vessel B&W Babcock & Wilcox BMI bottom mounted instrumentation BOP balance of plant BTP branch technical position BWR boiling water reactor CASS cast austenitic stainless steel CCW component cooling water CCCW closed cycle cooling water CETNA core exit thermocouple nozzle assembly CFR Code of Federal Regulations CLB current licensing basis C02 carbon dioxide CRD control rod drive CRDM control rod drive mechanism CS containment spray CST condensate storage tank Cu copper CUF cumulative usage factor CVCS chemical and volume control CvUSE Charpy upper-shelf energy CW circulating water DBA design basis accident DBD design basis document DBE design basis event DC direct current xiii AC ACI ACRS ADAMS ADV AERM AFW Aise AMP AMR ANSI ART ASME ASTM ATWS B&PV B&W BMI BOP BTP BWR CASS ecw ecew CETNA CFR CLB C02 CRD CRDM CS CST Cu eUF eves CvUSE CW DBA DBD DBE DC ABBREVIATIONS alternating current American Concrete Institute Advisory Committee on Reactor Safeguards Agencywide Document Access and Management System atmospheric dump valve aging effect requiring management auxiliary feedwater American Institute of Steel Construction aging management program aging management review American National Standards Institute adjusted reference temperature American Society of Mechanical Engineers American Society for Testing and Materials anticipated transient without scram Boiler and Pressure Vessel Babcock & Wilcox bottom mounted instrumentation balance of plant branch technical position boiling water reactor cast austenitic stainless steel component cooling water closed cycle cooling water core exit thermocouple nozzle assembly Code of Federal Regulations current licensing basis carbon dioxide control rod drive control rod drive mechanism containment spray storage tank copper cumulative usage factor chemical and volume control Charpy upper-shelf energy circulating water design basis accident design basis document design basis event direct current xiii ECCS emergency core cooling system EDG emergency diesel generator EFPY effective full-power year EHC electro-hydraulic control EMA equivalent margin analysis EN shelter or protectionEPRI Electric Power Research Institute EQ environmental qualification ER Environmental Report (Applicant's Environmental Report Operating License Renewal Stage)ESF engineered safety features FAC flow accelerated corrosion Fen environmental fatigue life correction factor FERC Federal Energy Regulatory Commission FLB flood barrier FLT filtration FMP Fatigue Monitoring Program FR Federal Register FRV 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 GElS Generic Environmental Impact Statement GL generic letter GSI generic safety issue H2 hydrogen HELB high-energy line breakHEPA high efficiency particulate airHPSI high pressure safety injection HVAC heating, ventilation, and air conditioning HX heat exchanger I&C instrumentation and controls JA instrument air IASCC irradiation assisted stress corrosion cracking ID IGA inside diameter intergranular attack IEEE Institute of Electrical and Electronics Engineers IGA intergranular attack IGSCC inter-granular stress corrosion cracking ILRT integrated leak rate testing IN information notice xiv ECCS EOG EFPY EHC EMA EN EPRI EQ ER ESF FAC Fen FERC FLB FLT FMP FR FRV FSAR ft-Ib FW FWST GALL GOC GElS GL GSI H2 HELB HEPA HPSI HVAC HX I&C IA IASCC IOIGA IEEE IGA IGSCC ILRT IN emergency core cooling system emergency diesel generator effective full-power year _ electro-hydraulic control equivalent margin analysis shelter or protection Electric Power Research Institute environmental qualification Environmental Report (Applicant's Environmental Report Operating License Renewal Stage) engineered-safety features flow accelerated corrosion environmental fatigue life correction factor Federal Energy Regulatory Commission flood barrier filtration Fatigue Monitoring Program Federal Register feedwater regulating valve final safety analysis report foot-pound feedwater fire water storage tank Generic Aging Lessons Learned Report general design criteria or general design criterion Generic Environmental Impact Statement generic letter generic safety issue hydrogen high-energy line break high efficiency particulate air high pressure safety injection heating, ventilation, and air conditioning heat exchanger instrumentation and controls instrument air irradiation assisted stress corrosion cracking inside diameter intergranular attack Institute of Electrical and Electronics Engineers intergranular attack inter-granular stress corrosion cracking integrated leak rate testing information notice xiv INPO Institute of Nuclear Power Operations IPA integrated plant assessment ISG interim staff guidance ISI inservice inspection KV or kV kilo-volt LBB leak before break LOCA loss of coolant accident LRA license renewal application MB missile barrier MFW main feedwater MIC microbiologically-influenced corrosion MIRVSP master integrated reactor vessel surveillance program MOV motor-operated valve MS main steam MSIV main steam isolation valve MWe megawatts-electric MWt megawatts-thermal n/cm2 neutrons per square centimeter NDE nondestructive examination NEI Nuclear Energy Institute NFPA National Fire Protection Association Ni nickel NPS nominal pipe size NRC US Nuclear Regulatory Commission NSSS nuclear steam supply system 02 oxygen OCCW open cycle cooling water OD IGA outside diameter intergranular attack ODSCC outside-diameter stress corrosion cracking 01 open item OTSG once through steam generator P&ID piping and instrumentation diagram PAB primary auxiliary building PB pressure boundary PBD program basis document pH potential of hydrogen PORV power-operated relief valve ppm parts per million PSPM periodic surveillance and preventive maintenance P-T pressure-temperature PTS pressurized thermal shock PVC polyvinyl chloride xv INPO IPA ISG lSI KVor kV LBB LOCA LRA MB MFW MIC MIRVSP MOV MS MSIV MWe MWt n/cm2 NOE NEI NFPA Ni NPS NRC NSSS 02 OCCW OOIGA OOSCC 01 OTSG P&ID PAB PB PBD pH PORV ppm PSPM P-T PTS PVC Institute of Nuclear Power Operations integrated plant assessment interim staff guidance inservice inspection kilo-volt leak before break loss of coolant accident license renewal application missile barrier main feedwater microbiologica"y-influenced corrosion master integrated reactor vessel surveillance program motor-operated valve main steam main steam isolation valve megawatts-electric megawatts-thermal neutrons per square centimeter nondestructive examination Nuclear Energy Institute National Fire Protection Association nickel nominal pipe size US Nuclear Regulatory Commission . nuclear steam supply system oxygen open cycle cooling water outside diameter intergranular attack outside-diameter stress corrosion cracking open item once through steam generator piping and instrumentation diagram primary auxiliary building pressure boundary program basis document potential of hydrogen power-operated relief valve parts per million periodic surveillance and preventive maintenance pressure-temperature

pressurized thermal shock polyvinyl chloride xv PW primary water makeup PWR pressurized water reactor PWSCC primary water stress corrosion cracking QA quality assurance RAI request for additional information RCP reactor coolant pump RCPB reactor coolant pressure boundary RCS reactor coolant system RG regulatory guide RHR residual heat removal RM radiation monitoring RO refueling outage RPV reactor pressure vessel RTNDT reference temperature nil ductility transition RTPTS reference temperature for pressurized thermal shock RTD resistance temperature detector RV reactor vessel RVCH reactor vessel closure head RVLIS reactor vessel level indication system RW river water RWST refueling water storage tank SA stress allowables SBO station blackout SC structure and component SCC stress-corrosion cracking SER safety evaluation report SFPC spent fuel pit/pool cooling SG steam generator SGBD steam generator blowdown SI safety injection SMP structures monitoring program S02 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 Ap'plications for Nuclear Power Plants 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) xvi PW PWR PWSCC QA RAI RCP RCPB RCS RG RHR RM RO RPV RTNDT RTpTS RTD RV RVCH RVLlS RW RWST SA SBO SC SCC SER SFPC SG SGBD SI SMP S02 SOC SOV SPU SR SRP-LR SSC SSE SSFS SW TLAA TS primary water makeup pressurized water reactor primary water stress corrosion cracking quality assurance request for additional information reactor coolant pump reactor coolant pressure boundary reactor coolant system regulatory guide residual heat removal radiation monitoring refueling outage reactor pressure vessel reference temperature nil ductility transition reference temperature for pressurized thermal shock resistance temperature detector reactor vessel reactor vessel closure head reactor vessel level indication system river water refueling water storage tank stress allowables station blackout structure and component stress-corrosion cracking safety evaluation report spent fuel pit/pool cooling steam generator steam generator blowdown safety injection structures monitoring program sulfur dioxide statement of consideration sOlenoid-operated valve stretch power uprate surveillance requirement II Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants system, structure, and component safe-shutdown earthquake safety system function sheets service water time-limited aging analysis technical specification( s) xvi UFSAR Updated Final Safety Analysis Report USE upper-shelf energy UT ultrasonic testing UV ultraviolet VCT volume control tank VHP vessel head penetration Yr year Zn zinc 1/4 T one-fourth of the way through the vessel wall measured from the internal surface of the vessel xvii UFSAR USE UT UV veT VHP Yr Zn 1/4 T Updated Final Safety Analysis Report upper-shelf energy . ultrasonic testing ultraviolet volume control tank vessel head penetration year zinc one-fourth of the way through the vessel wall measured from the internal surface of the vessel xvii

SECTION 1 INTRODUCTION AND GENERAL DISCUSSION

1.1 Introduction

This document is a safety evaluation report (SER) on the license renewal application (LRA) for Three Mile Island Nuclear Station, Unit 1 (TMI-1), as filed by AmerGen Energy Company, LLC (AmerGen or the applicant). By letter dated January 8, 2008, AmerGen submitted its application to the U.S. Nuclear Regulatory Commission (NRC) for renewal of the TMI-1 operating license for an additional 20 years. The NRC staff (the staff) prepared this report, which summarizes the results of its safety review of the renewal application, for compliance with the requirements of Title 10, Part 54, of the Code of Federal Regulations (10 CFR Part 54), "Requirements for Renewal of Operating Licenses for Nuclear Power Plants." The NRC license renewal project manager for the TMI-1 license renewal review is Mr. Jay Robinson. Mr. Robinson can be contacted by telephone at 301-415-2878 or by e-mail at Jay.Robinson@nrc.gov. Alternatively, written correspondence may be sent to: U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Division of License Renewal Washington, D.C. 20555-0001 Attention: Jay Robinson, Mail Stop 0-11 F1 By letter dated June 20, 2008, as supplemented on July 17, 2008, the applicant and Exelon Generation Company, LLC, (EGC)'submitted an application to the NRC requesting approval of the transfer of the operating license for TMI-1 to the extent held by the applicant, to EGC. The staff noted that the transfer to EGC will eliminate AmerGen as owner and operator of TMI-1 and that after the transfer, EGC would be the sole licensed owner and operator of TMI-1. By letter dated December 23, 2008, the NRC issued an order approving the transfer of the operating license for TMI-1 from AmerGen to EGC, subject to two conditions. By letter dated January 8, 2009, EGC informed the NRC that the completion of the transfer of TMI-1 from AmerGen to EGC occurred on January 8, 2009.By letter dated January 8, 2009, the Commission issued Amendment No. 267 to Facility Operating License No. DPR-50, for TMI-1, amending the operating license at TMI-1 to reflect the new licensee due to the merger of AmerGen into its parent, EGC.For the purposes of the SER, the use of the term "applicant" refers to AmerGen Energy Company, LLC up to and including January 7, 2009, and to Exelon Generation Company, LLC on and after January 8, 2009.In its January 8, 2008, submission letter, the applicant requested renewal of the operating license issued under Section 104b (Operating License No. DPR-50) of the Atomic Energy Act of 1954, as amended, for TMI-1, for a period of 20 years beyond the current license expiration at midnight, April 14, 2014. TMI-1 is located approximately 10 miles southeast of Harrisburg, Pennsylvania. The staff issued the original construction permit for TMI-1 on May 18, 1968, and the operating license on April 19, 1974. The plant's nuclear steam supply system consists of a 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 Three Mile Island Nuclear Station, Unit 1 (TMI-1), as filed by AmerGen Energy Company, LLC (AmerGen or the applicant). By letter dated January 8, 2008, AmerGen submitted its application to the U.S. Nuclear Regulatory Commission (NRC) for renewal of the TMI-1 operating license for an additional 20 years. The NRC staff (the staff) prepared this report, which summarizes the results of its safety review of the renewal application, for compliance with the requirements of* Title 10, Part 54, of the Code of Federal Regulations (10 CFR Part 54), "Requirements for Renewal of Operating Licenses for Nuclear Power Plants." The NRC license renewal project manager for the TMI-1 license renewal review is Mr. Jay Robinson. Mr. Robinson can be contacted by telephone at 301-415-2878 or bye-mail at Jay.Robinson@nrc.gov. Alternatively, written correspondence may be sent to: U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Division of License Renewal Washington, D.C. 20555-0001 Attention: Jay Robinson, Mail Stop 0-11 F1 By letter dated June 20,2008, as supplemented on July 17, 2008, the applicant and Exelon Generation Company, LLC, (EGG) submitted an application to the NRC requesting approval of the transfer of the operating license for TMI-1 to the extent held by the applicant. to EGC. The staff noted that the transfer to EGC will eliminate AmerGen as owner and operator of TMI-1 and that after the transfer, EGC would be the sole licensed owner and operator of TMI-1. By letter dated December 23, 2008, the NRC issued an order approving the transfer of the operating license for TMI-1 from AmerGen taEGC, subject to two conditions. By letter dated January 8, 2009, EGC informed the NRC that the completion of the transfer of TMI-1 from AmerGen to EGC occurred on January 8, By letter dated January 8, 2009, the Commission issued Amendment No. 267 to Facility Operating License No. DPR-50, for TMI-1, amending the operating license at TMI-1 to reflect the new licensee due to the merger of AmerGen into its parent, EGC. For the purposes of the SER, the use of the term "C3Pplicant" refers to AmerGen Energy Company, LLC up to and including January 7,2009, and to Exelon Generation Company, LLC on and after January 8, 2009. In its January 8, 2008, submission letter, the applicant requested renewal of the operating license issued under Section 104b (Operating License No. DPR-50) of the Atomic Energy Act of 1954, as amended, for TMI-1, for a period of 20 years beyond the current license expiration at midnight, April 14, 2014. TMI-1 is located approximately 10 miles southeast of Harrisburg, Pennsylvania. The staff issued the original construction permit for TMI-1 on May 18,1968, and the operating license on April 19, 1974. The plant's nuclear steam supply system consists of a 1-1 Babcock & Wilcox pressurized-water reactor with a lowered loop. The primary containment is of the dry ambient type. The balance of the plant was originally designed by Gilbert Associates and constructed by United Engineers and Constructors .TMI-1 operates at a licensed power output of 2,568 megawatt-thermal, with a gross electrical output of approximately 852 megawatt-electric. The updated final safety analysis report (UFSAR) contains details of the plant and the site.The license renewal process consists of two concurrent reviews: a technical review of safety issues and an environmental review. The NRC regulations in 10 CFR Parts 54 and 51, respectively, set forth requirements for these reviews. The safety review for the TMI-1 license renewal is based on the applicant's LRA and on the responses to the staffs requests for additional information (RAIs). The applicant supplemented and clarified its responses to the LRA and RAIs in audits, meetings, and docketed correspondence. Unless otherwise noted, the staff reviewed and considered information submitted through February 20, 2009. The staff lýreviewed the information received after that date on a case-by-case basis, depending on the stage of the safety review and the volume and complexity of the information. The public may view the LRA and all pertinent information and materials, including the UFSAR, at the following locations: The NRC Public Document Room, One White Flint North, 11555 Rockville Pike (First Floor), Rockville, MD 20852-2738 (301-415-4737/800-397-4209); the Middletown Public Library, 20 North Catherine Street, Middletown, PA 17057; the Penn State Harrisburg Library, 351 Olmsted Drive, Middletown, PA 17057; and the Londonderry Township Municipal Building, 783 South Geyers Church Road, Middletown, PA 17057. In addition, the public may find the LRA, as well as materials related to the license renewal review, on the NRC website.This SER summarizes the results of the staffs safety review of the LRA and describes the technical details considered in the evaluation of safety aspects of the unit's proposed operation for an additional 20 years beyond the term of the current operating license. The staff reviewed the LRA in accordance with NRC regulations and the guidance of NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants" (SRP-LR), dated July 2001.SER Sections 2 through 4 address the staff's evaluation of license renewal issues considered during its review of the application. SER Section 5 is reserved for the report of the Advisory, Committee on Reactor Safeguards (ACRS). The conclusions of this report are in SER Section 6.SER Appendix A is a table that identifies the applicant's commitments for the renewal of the operating license. SER Appendix B is a chronology of the principal correspondence between thestaff and the applicant related to the review of the application. SER Appendix C is a list of principal contributors to the SER. SER Appendix D is a bibliography of the references in support of the review.In accordance with 10 CFR Part 51, the staff prepared a draft plant-specific supplement to the Generic Environmental Impact Statement (GELS). This supplement discusses the environmental considerations related to license renewal for TMI-1. The staff issued draft Supplement 37 to NUREG-1437, "Generic Environmental Impact Statement for License Renewal of Nuclear Plants, Regarding Three Mile Island Nuclear Station, Unit 1, Draft Report for Comment," in December of 2008.1-2 Babcock & Wilcox pressurized-water reactor with a lowered loop. The primary containment is of the dry ambient type. The balance of the plant was originally designed by Gilbert Associates and constructed by United Engineers and Constructors. TMI-1 operates at a licensed power output of 2,568 megawatt-thermal, with a gross electrical output of approximately 852 megawatt-electric. The updated final safety analysis report (UFSAR) contains details of the Ii plant and the site. The license renewal process consists of two concurrent reviews: a technical review of safety issues and an environmental review. The NRC regulations in 10 CFR Parts 54 and 51, respectively, set forth requirements for these reviews. The safety review for the TMI-1 license renewal is based on the applicant's LRA and on the responses to the staffs requests for additional information (RAls). The applicant supplemented and clarified its responses to the LRA and RAls in audits, meetings, and docketed correspondence. Unless otherwise noted, the staff reviewed and considered information submitted through February 20, 2009. The staff ;1 reviewed the information received after that date on a case-by-case basis, depending on the stage of the safety review and the volume and complexity of the information. The public may view the LRA and all pertinent information and materials, including the UFSAR, at the following locations: The NRC Public Document Room, One White Flint North, 11555 Rockville Pike (First Floor), Rockville, MD 20852-2738 (301-415-4737/800-397-4209); the Middletown Public Library, 20 North Catherine Street, Middletown, PA 17057; the Penn State Harrisburg Library, 351 Olmsted Drive, Middletown, PA 17057; and the Londonderry Township Municipal Building, 783 South Geyers Church Road, Middletown, PA 17057. In addition, the public may find the LRA, as well as materials related to the license renewal review, on the r This SER summarizes the results of the staffs safety review of the LRA and describes the technical details considered in the evaluation of safety aspects of the unit's proposed operation for an additional 20 years beyond*the term of the current operating license. The staff reviewed the LRA in accordance with NRC regulations and the guidance of NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants" (SRP-LR), dated July 2001. SER Sections 2 through 4 address the staff's evaluation of license renewal issues considered during its review of the application. SER Section 5 is reserved for the report of the AdviSOry Committee on Reactor Safeguards (ACRS). The conclusions of this report are in SER . Section 6. SER Appendix A is a table that identifies the applicant's commitments for the renewal of operating license. SER Appendix B is a chronology of the principal correspondence between the staff and the applicant related to the review of the application. SER Appendix C is a list of principal contributors to the SER. SER Appendix D is a bibliography of the references in support of the review. In accordance with 10 CFR Part 51, the staff prepared a draft plant-specific supplement to the Generic Environmental Impact Statement (GElS). This supplement discusses the environmental considerations related to license renewal for TMI-1. The staff issued draft Supplement 37 to NUREG-1437, "Generic Environmental Impact Statement for License Renewal of Nuclear Plants, Regarding Three Mile Island Nuclear Station, Unit 1, Draft Report for Comment," in December of 2008. 1-2

1.2 License

Renewal Background Pursuant to the Atomic Energy Act of 1954, as amended, and NRC regulations, operating licenses for commercial power reactors are issued for 40 years. These licenses can be renewed for up to 20 additional years. The original 40-year license term was selected on the basis of economic and antitrust considerations, rather than on technical limitations; however, some individual plant and equipment designs may have been engineered based on an expected 40-year service life.In 1982, the staff anticipated interest in license renewal and held a workshop on nuclear power plant aging. This workshop led the staff to establish a comprehensive program plan for nuclear plant aging research. On the basis of the results of that research, a technical review group concluded that many aging phenomena are readily manageable and pose no technical issues that would preclude 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 the license renewal rule in 10 CFR Part 54 (the Rule). The staff participated in an industry-sponsored demonstration program to apply the Rule to a pilot plant and to gain experience necessary to develop implementation guidance. To establish a scope of review for license renewal, the Rule defined age-related degradation unique to license renewal;however, during the demonstration program, the staff found that many aging mechanisms occur to plant systems and components with effects managed during the initial license period. In addition, the staff found that the scope of the review did not allow sufficient credit for existing programs, particularly the implementation of the Maintenance Rule, which also manages plant-aging phenomena. As a result, the staff amended the Rule in 1995. As amended, 10 CFR Part 54 established a regulatory process that is simpler, more stable, and more predictable than the previous Rule. In particular, as amended, 10 CFR Part 54 focused on management of adverse aging effects rather than on identification of age-related degradation unique to license renewal. The staff initiated these rule changes to ensure that important systems, structures, and components (SSCs) will continue to perform their intended functions during the period of extended operation. In addition, the revised Rule clarified and simplified the integrated plant assessment 'process for consistency with the revised focus on passive, long-lived structures and components (SCs).In parallel with these efforts, in a separate rulemaking effort, the staff amended 10 CFR Part 51 to focus the scope of the review of environmental impacts of license renewal and fulfill the staff's responsibilities under the National Environmental Policy Act of 1969 (NEPA).1.2.1 Safety Review LiCense renewal requirements for power reactors are based on two key principles: (1) The regulatory process is adequate to ensure that the licensing bases of all currently operating plants maintain an acceptable level of safety, with the possible exception of the detrimental aging effects on the function of certain SSCs, as well as a few other safety-related issues, during the period of extended operation 1-3 1.2 License Renewal Background Pursuant to the Atomic Energy Act of 1954, as amended, and NRC regulations, operating licenses for commercial power reactors are issued for 40 years. These licenses can be renewed for up to 20 additional years. The original 40-year license term was selected on the basis of economic and antitrust considerations, rather than on technical limitations; however, some individual plant and equipment designs may have been engineered based on an expected 40-year service life. In 1982, the staff anticipated interest in license renewal and held a workshop on nuclear power plant aging. This workshop led the staff to establish a comprehensive program plan for nuclear plant aging research. On the basis of the results of that research, a technical review group concluded that many aging phenomena are readily manageable and pose no technical issues that would preclude 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 the license renewal rule in1 0 CFR Part 54 (the Rule). The staff participated in an industry-sponsored demonstration program to apply the Rule to a pilot plant and to gain experience necessary to develop implementation guidance. To establish a scope of review for license renewal, the Rule defined age-related degradation unique to license renewal; however, during the demonstration program, the staff found that many aging mechanisms occur to plant systems and components with effects managed during the initial license period. In addition, the staff found that the scope of the review did not allow sufficient credit for existing programs, particularly the implementation of the Maintenance Rule, which also manages . plant-aging phenomena. As a result, the staff amended the Rule in 1995. As amended, 10 CFR Part 54 established a regulatory process that is simpler, more stable, and more predictable than the previous Rule. In particular, as amended, 10 CFR Part 54 focused on management of adverse aging effects rather than on identification of age-related degradation unique to license renewal. The staff initiated these rule changes to ensure that important systems, structures, and components (SSCs) will continue to perform their intended functions during the period of extended operation. In addition, the revised Rule clarified and simplified the integrated plant assessment 'process for consistency with the revised focus on passive, long-lived structures and components (SCs). In parallel with these efforts, in a separate rulemaking effort, the staff amended 10 CFR Part 51 to focus the scope of the review of environmental impacts of license renewal and fulfill the staff's responsibilities under the National Environmental Policy Act of 1969 (NEPA). 1.2.1 Safety Review License renewal requirements for power reactors are based on two key principles: (1 ) The regulatory process is adequate to ensure that the licensing bases of all currently operating plants maintain an acceptable level of safety, with the possible exception of the detrimental aging effects on the function of certain SSCs, as well as a few other safety-related issues, during the period of extended operation 1-3 (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 defines the scope of license renewal as including SSCs (1) that are safety-related, (2) whose failure could affect safety-related functions, and (3) that are relied on to demonstrate compliance with NRC regulations for fire protection, environmental qualification , pressurized thermal shock, anticipated transient without scram, and station blackout.Pursuant to 10 CFR 54.21(a), an applicant for a renewed license must review all SSCs within the scope of the Rule to identify SCs subject to an aging management review (AMR). SCs subject to an AMR are those which perform an intended function without moving parts or without a change in configuration or properties (i.e., are "passive"), and are not subject to replacement based on a qualified life or specified time period (i.e., are "long lived"). As required by 10 CFR54.21(a), an applicant for a renewed license must demonstrate that aging effects will be managed in such a way that the intended function(s) of those SSCs will be maintained, consistent with the current licensing basis (CLB), for the period of extended operation; however, active equipment is considered adequately monitored and maintained by existing programs. In other words, detrimental aging effects that may affect active equipment are readily detectable and can be identified and corrected through routine surveillance, performance monitoring, and maintenance. Surveillance and maintenance programs for active equipment, as well as other maintenance aspects of plant design and licensing basis, are required throughout the period of extended operation.. Pursuant to 10 CFR 54.21(d), each LRA is required to include an UFSAR Supplement that must have a summary description of the applicant's programs and activities for managing aging effects and the evaluation of time-limited aging analyses (TLAAs) for the period of extended operation. License renewal also requires TLAA identification and updating. During the plant design phase, certain assumptions are made about the length of time the plant can operate. These.assumptions are incorporated into design calculations for several plant SSCs. In accordancewith 10 CFR'54.21(c)(1), the applicant must show that these calculations will remain valid for the period of extended operation, project the analyses to the end of the period of extended operation, or demonstrate that effects of aging on these SSCs can be adequately managed for the period of extended operation. In 2001, the staff developed and issued Regulatory Guide (RG) 1.188, "Standard Format and Content for Applications to Renew Nuclear Power Plant Operating Licenses." This RG endorses Nuclear Energy Institute (NEI) 95-10, Revision 3, "Industry Guideline for Implementing the Requirements of 10 CFR Part 54 -The License Renewal Rule," issued in March 2001 by theNEI. NEI 95-10 details an acceptable method of implementing the Rule. The staff also used, the SRP-LR to review this application. In its LRA, the applicant stated that it fully utilized the process defined in NUREG-1 801,"Generic Aging Lessons Learned (GALL) Report," issued in July 2001 and subsequently revised in September 2005. The GALL Report provides a summary of staff-approved aging management programs (AMPs) for the aging of many SCs subject to an AMR. If an applicant commits to implementing these staff-approved AMPs, the time, effort, and resources to review an applicant's LRA can be greatly reduced, thereby improving the efficiency and effectiveness 1-4 (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 defines the scope of license renewal as including SSCs (1) that are safety-related, (2) whose failure could affect safety-related functions, and (3) that are relied on to demonstrate compliance with NRC regulations for fire protection, environmental qualification, pressurized thermal shock, anticipated transient without scram, and station blackout. Pursuant to 10 CFR 54.21(a), an applicant for a renewed license must review all SSCs within the scope of the Rule to identify SCs subject to an aging management review (AMR). SCs subject to an AMR are those which perform an intended function without moving parts or without a change in configuration or properties (Le., are "passive"), and are not subject to replacement based on a qualified life or specified time period (Le., are "long lived"). As required by 10 CFR 54.21 (a), an applicant for a renewed license must demonstrate that aging effects will be managed in such a way that the intended function(s) of those SSCs will be maintained, consistent with the current licensing basis (CLB), for the period of extended operation; however, active equipment is considered adequately monitored and maintained by existing programs. In other words, detrimental aging effects that may affect active equipment are readily detectable and can be identified and corrected through routine surveillance, performance monitoring, ahd 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), each LRA is required to include an UFSAR Supplement that /nust have a summary description of the applicant's programs and activities for managing aging effects and the evaluation of time-limited aging analyses (TLAAs) for the period of extended operation. License renewal also requires TLAA identification and updating. During the plant design phase, certain assumptions are made about the length of time the plant can operate. These assumptions are incorporated into design calculations for several plant SSCs. In accordanc,e with 10 CFR54.21 (c)(1), the applicant must show that these calculations will remain valid for the period of extended operation, project the analyses to the end of the period of extended operation, or demonstrate that effects of aging on these SSCs can be adequately managed for the period of extended operation. In 2001, the staff developed and issued Regulatory Guide (RG) 1.188, "Standard Format arid Content for Applications to Renew Nuclear Power Plant Operating Licenses." This RG endorses Nuclear Energy Institute (NEI) 95-10, Revision 3, "Industry Guideline for Implementing the Requirements of 10 CFR Part 54.-The License Renewal Rule," issued in March 2001 by the NEI. NEI 95-10 details an acceptable methoq of implementing the Rule. The staff also used, the SRP-LR to review this application. ' In its LRA, the applicant stated that it fully utilized the process defined in NUREG-1801, "Generic Aging Lessons Learned (GALL) Report," issued in July 2001 and subsequently re*ised in September 2005. The GALL Report provides a summary of staff-approved aging management programs (AMPs) for the aging of many SCs subject to an AMR. If an applicant commits to implementing these staff-approved AMPs, the time, effort, and resources to revi,ew an applicant's LRA can be greatly reduced, thereby improving the efficiency and effectivenErss 1-4 of the license renewal review process. The GALL Report summarizes the aging managementevaluations, programs, and activities credited for managing aging for most SCs used throughout the industry. The report is also a reference for both applicants and staff reviewers to quickly identify AMPs and activities that can provide adequate aging management during the period of extended operation.

1.2.2 Environmental

Review In December 1996, the staff revised the environmental protection regulations to facilitate the environmental review for license renewal. The staff prepared a "Generic Environmental Impact Statement (GELS) for License Renewal of Nuclear Plants" (NUREG-1437, Revision 1) to document its evaluation of the possible environmental impacts associated with renewing licenses of nuclear power plants. For certain types of environmental impacts, the GElS establishes generic findings applicable to all nuclear power plants. These generic findings are codified in Appendix B to Subpart A of 10 CFR Part 51. Pursuant to 10 CFR 51.53(c)(3)(i), an applicant for license renewal may incorporate these generic findings in its environmental report.In accordance with 10 CFR 51.53(c)(3)(ii), an environmental report must also include analyses of environmental impacts that must be evaluated on a plant-specific basis (i.e., Category 2 issues).In accordance with NEPA and the requirements of 10 CFR Part 51, the staff performed a plant-specific review of the environmental impacts of license renewal, including whether the GElS had not considered new and significant information. As part of its scoping process, the staff held a public meeting on May 1, 2008 in Middletown, Pennsylvania, to identify plant-specific environmental issues. The staff's draft plant-specific GElS Supplement 37, issued in December of 2008, documents the results of the environmental review and includes a preliminary recommendation for license renewal action. Another public meeting was held on February 24, 2009 in Middletown, Pennsylvania, to discuss the draft plant-specific GElS Supplement

37. After considering comments on the draft, the staff prepared and published on June 25, 2009 a final plant-specific supplement to the GElS separately from this report (ADAMs Accession No. ML091-751063).

1.3 Principal

Review Matters Part 54 of 10 CFR describes the requirements for renewing operating licenses for nuclear power plants. The staff performed its technical review of the LRA in accordance with NRC guidance and 10 CFR Part 54 requirements. Section 54.29 of 10 CFR sets forth the standards for renewing a license. This SER describes the results of the staff's safety review.Under 10 CFR 54.19(a), the NRC requires a license renewal applicant to submit general information. The applicant provided this general information in LRA Section 1, which it submitted, by letter dated January 8, 2008. The staff reviewed LRA Section 1 and found that theapplicant had submitted the information required by 10 CFR 54.19(a).Under 10 CFR 54.19(b), the staff requires that each 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." The applicant stated the following in LRA Section 1.1.10 on this issue: 10 CFR 54.19(b) requires that "each application must include conforming changes to the standard indemnity agreement, 10 CFR 140.92, Appendix B, to account for the 1-5 of the license renewal review process. The GALL Report summarizes the aging management evaluations, programs,* and activities credited for managing aging for most SCs used throughout the industry. The report is also a reference for both applicants and staff reviewers to quickly identify AMPs and activities that can provide adequate aging management during the period of extended operation.

1.2.2 Environmental

Review In December 1996, the staff revised the environmental protection regulations to facilitate the environmental review for license renewal. The staff prepared a "Generic Environmental Impact Statement (GElS) for License Renewal of Nuclear Plants" (NUREG-1437, Revision 1) to document its evaluation of the possible environmental impacts associated with renewing licenses of nuclear power plants. For certain types of environmental impacts, the GElS establishes generic findings applicable to all nuclear power plants. These generic findings are codified in Appendix S to Subpart A of 10 CFR Part 51. Pursuant to 10 CFR 51.53(c)(3)(i), an applicant for license renewal may incorporate these generic findings in its environmental report. In accordance with 10*CFR 51.53(c)(3)(ii), an environmental report must also include analyses of environmental impacts that must be evaluated on a plant-specific basis (Le., Category 2 issues). In accordance with NEPA and the requirements of 10 CFR Part 51, the staff performed a plant-specific review of the environmental impacts of license renewal, including whether the GElS had not considered new and significant information. As part of its scoping process, the staff held a public meeting on May 1, 2008 in Middletown, Pennsylvania, to identify plant-specific environmental issues. The staff's draft plant-specific GElS Supplement 37, issued in December of 2008, documents the results of the environmental review and includes a preliminary recommendation for license renewal action. Another public meeting was held on February 24, 2009 in Middletown, Pennsylvania, to discuss the draft plant-specific GElS Supplement

37. After conSidering comments on the draft, the staff prepared and published on June 25, 2009 a final plant-specific supplement to the GElS separately from this report (ADAMs Accession No. ML091751063).

1.3 Principal

Review Matters Part 54 of 10 CFR describes the requirements for renewing operating licenses for nuclear power plants. The staff performed its technical review of the LRA in accordance with NRC guidance and 10 CFR Part 54 requirements. Section 54.29 of 10 CFR sets forth the standards for renewing a license. This SER describes the results of the staff's safety review. Under 10 CFR 54.19(a), the NRC requires a license renewal applicant to submit general information. The applicant provided this general information in LRA Section 1, which it submitted, by letter dated January 8,2008. The staff reviewed LRA Section 1 and found that the applicant had submitted the information required by 10 CFR 54.19(a). Under 10 CFR 54.19(b), the staff requires that each LRA include "conforming changes to the standard indemnity agreement, 10 CFR 140.92, Appendix S, to account for the expiration term of the proposed renewed license." The applicant stated the following in LRA Section 1.1.10 on this issue: . 10 CFR 54.19(b) requires that "each application must include conforming changes to the standard indemnity agreement, 10 CFR 140.92, Appendix S, to account for the 1-5 expiration term of the proposed renewed license." The current indemnity agreement (No. B-64) for TMI-1 states in Article VII that the agreement shall terminate at the time of expiration of that license specified in Item 3 of the Attachment to the agreement, which is the last to expire; provided that, except as may otherwise be provided in applicable regulations or orders of the Commission, the term of this agreement shall not terminate until all the radioactive material has been removed from the location and transportation of the radioactive material from the location has ended as defined in subparagraph 5(b), Article I. Item 3 of the Attachment to the indemnity agreement includes license number, DPR-50. Applicant requests that any necessary conforming changes be made to Article VII and Item 3 of the Attachment, and any other sections of the indemnity agreement as appropriate to ensure that the indemnity agreement continues to apply during both the terms of the current license and the terms of the renewed license. Applicant understands that no changes may be necessary for this purpose if the current license number is retained.The staff intends to maintain the original license number upon issuance of the renewed license, if approved. Therefore, conforming changes to the indemnity agreement need not be made and the 10 CFR 54.19(b) requirements have been met.Under 10 CFR 54.21, the staff requires that each LRA contain: (a) an IPA (b) a description of any CLB changes during the staffs review of the LRA (c) an evaluation of TLAAs (d) an UFSAR Supplement LRA Sections 3 and 4 and Appendix B address the license renewal requirements of 10 CFR 54.21(a), (b), and (c). LRA Appendix A satisfies the license renewal requirements of 10 CFR 54.21(d).Under 10 CFR 54.21(b), the staff requires that each year following submission of the LRA, and at least 3 months before the scheduled completion of the staffs review, the applicant submit an LRA amendment identifying any CLB changes of the facility that materially affect the contents of the LRA, including the UFSAR Supplement. The applicant submitted an update to the LRA by letter dated January 9, 2009, summarizing the CLB changes that have occurred during the staff's review of the LRA which satisfies the requirements of 10 CFR 54.21(b).Under 10 CFR 54.22, the staff requires that an applicant's LRA include changes or additions to the technical specifications necessary to manage aging effects during the period of extended operation. In LRA Appendix D, the applicant stated the following: As part of the TMI-1 aging management review, AmerGen identified and committed to the replacement of both Once Through Steam Generators (OTSGs) prior to the period of extended operation. In association with this replacement, a separate Technical Specification Change Request will be submitted. No Technical Specification changes oradditions were identified as necessary to manage the effects of aging during the period of extended operation and as such no Technical Specification changes or additions lare included with this License Renewal Application. 1-6 expiration term of the proposed renewed license." The current indemnity agreement (No. B-64) for TMI-1 states in Article VII that the agreement shall terminate at the time of expiration of that license specified in Item 3 of the Attachment to the agreement, which is the last to expire; provided that, except as may otherwise be provided in applicable regulations or orders of the Commission, the term of this agreement shall not terminate until all the radioactive material has been removed from the location and transportation of the radioactive material from the location has ended as defined in subparagraph 5(b}, Article I. Item 3 of the Attachment to the indemnity agreement includes license number, DPR-50. Applicant requests that any necessary conforming changes be made to Article* VII and Item 3 of the Attachment, and any other sections of the indemnity agreement as appropriate to ensure that the indemnity agreement continues to apply during both the terms of the current license and the terms of the renewed license. Applicant understands that no changes may be necessary for this purpose if the current license number is retained. The staff intends to maintain the original license number upon issuance of the renewed license, if approved. Therefore, conforming changes to the indemnity agreement need not be made and the 10 CFR 54.19(b} requirements have been met. Under 10 CFR 54.21, the staff requires that each LRA contain: (a) an IPA (b) a description of any CLB changes during the staffs review of the LRA (c) an evaluation of TLAAs (d) an UFSAR Supplement LRA Sections 3 and 4 and Appendix B address the license renewal requirements of 10 CFR 54.21(a}, (b), and (c). LRA Appendix A satisfies the license renewal requirements of 10 CFR 54.21(d). . Under 10 CFR 54.21 (b), the staff requires that each year following submission of the LRA, and at least 3 months before the scheduled completion of the staffs review, the applicant submit an LRA amendment identifying any CLB changes of the facility that materially affect the contents of the LRA, including the UFSAR Supplement. The applicant submitted an update to the LRA by letter dated January 9, 2009, summarizing the CLB changes that have occurred during the* staff's review of the LRA which satisfies the requirements of 10 CFR 54.21 (b) . Under 10 CFR 54.22, the staff requires that an applicant's LRA include changes or additions to the technical specifications necessary to manage aging effects during the period of extended operation. In LRA Appendix D, the applicant stated the following: As part of the TMI-1 aging management review, AmerGen identified and committedto the replacement of both Once Through Steam Generators (OTSGs) prior to the period of extended operation. In association with this replacement, a separate Technical Specification Change Request will be submitted. No Technical Specification changes or additions were identified as necessary to manage the effects of aging during the period of extended operation and as such no Technical Specification changes or additions11are included with this License Renewal Application. 1-6 The staff evaluated the technical information required by 10 CFR 54.21 and 10 CFR 54.22 in accordance with NRC regulations and the guidance of the SRP-LR. SER Sections 2, 3, and 4document the staff's evaluation of the technical information in the LRA.As required by 10 CFR 54.25, the ACRS will issue a report to document its evaluation of the staff's LRA review and associated SER. SER Section 5 will incorporate the ACRS report once it is issued. SER Section 6 will document the findings required by 10 CFR 54.29.The final plant-specific GElS supplement will document the staff's evaluation of the environmental information required by 10 CFR 54.23 and will specify the considerations for renewing the TMI-1 license. The staff will prepare the supplement separately from the SER.1.4 Interim Staff Guidance License renewal is a living program. The staff, industry, and other interested stakeholders gain experience and develop lessons learned with each renewed license. The lessons learned address the staffs performance goals of maintaining safety, improving effectiveness and efficiency, reducing regulatory burden, and increasing public confidence. Interim staff guidance (ISG) is documented for use by the staff, industry, and other interested stakeholders until incorporated into such license renewal guidance documents as the SRP-LR and the GALL Report.Table 1.4-1 shows the current 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 Issuea Purpose -SER Section (Approved ISG, No.),~a LR-ISG-19B Cracking of nickel-alloy components in the reactor 3.0.3.3.1 coolant pressure boundary This LR-ISG is under development. The Nuclear Energy Institute (NEI) and the Electric Power Research Institute Materials Reliability Program (EPRI-MRP) are developing an augmented inspection program for GALL AMP XI.M1 1-B,"Nickel-Alloy Base-Metal Components and Welds in the Reactor Coolant Pressure Boundary." This AMP will not be completed until after the staff approves an augmented inspection program for nickel-alloy base metal components and welds as proposed by the ERPI-MRP.LR-ISG-2006-01 Corrosion of the Mark I steel containment drywell Not Applicable to TMI-1 shell I 1.5 Summary of Open Items After its review of the LRA, including additional information submitted through June 29, 2009, the staff has identified no open items. An item would be considered open if the applicant had not presented a sufficient basis for issue resolution. 1-7 The staff evaluated the technical information required by 10 CFR 54.21 and 10 CFR 54.22 in accordance with NRC regulations and the guidance of the SRP-lR. SER Sections 2, 3, and 4 document the staff's evaluation of the technical information in the lRA. As required by 10 CFR 54.25, the ACRS will issue a report to document its evaluation of the staff's lRA review and associated SER. SER Section 5 will incorporate the ACRS report once it is issued. SER Section 6 will document the findings required by 10 CFR 54.29. The final plant-specific GElS supplement will document the staff's evaluation of the environmental information required by 10 CFR 54.23 and will specify the considerations for renewing the TMI-1 license. The staff will prepare the supplement separately from the SER. 1.4 Interim Staff Guidance license renewal is a living program. The staff, industry, and other interested stakeholders gain experience and develop lessons learned with each renewed license. The lessons learned address the staff's performance goals of maintaining safety, improving effectiveness and effiCiency, reducing regulatory burden, and increasing public confidence. Interim staff guidance (ISG) is documented for use by the staff, industry, and other interested stakeholders until incorporated into such license renewal guidance documents as the SRP-lR and the GALL Report. Table 1.4-1 shows the current and proposed ISGs, as well as the SER sections in which they are addressed. LR-ISG-19B LR-ISG-2006-01 Table 1.4-1 Current and Proposed Interim Staff Guidance Cracking of nickel-alloy components in the reactor 3.0.3.3.1 coolant pressure boundary This LR-ISG is under development. The Nuclear Energy Institute (NEI) and the Electric Power Research Institute Materials Reliability Program (EPRI-MRP) are developing an augmented inspection program for GALL AMP XI.M11-B, "Nickel-Alloy Base-Metal Components and Welds in the Reactor Coolant Pressure Boundary.* This AMP will not be completed until after the staff approves an augmented inspection program for nickel-alloy base metal components and welds as proposed by the ERPI-MRP. Corrosion of the Mark I steel containment drywell Not Applicable to TMI-1 shell 1.5 Summary of Open Items After its review of the LRA, including additional information submitted through June 29, 2009, the staff has identified no open items. An item would be considered open if the applicant had not presented a sufficient basis for issue resolution. 1-7

1.6 Summary

of Confirmatory Items Following the staffs review of the LRA, including additional information and clarifications submitted through June 29, 2009, the staff closed previous confirmatory item (CI) 4.3.2-1 identified in the "Safety Evaluation Report With Open Items Related to the License Renewal of Three Mile Island Nuclear Station Unit 1" (ADAMS Accession No. ML090710604). The staff has identified no other confirmatory items. An item would be considered confirmatory if the staff and the applicant reached a satisfactory resolution, but the resolution had not yet been formally'submitted to the staff.In closed Cl 4.3.2-1 the staff noted that the maximum Fen values for carbon steels and low alloy steels (1.74, 2.455, respectively) are based, in part, on an assumed dissolved oxygen (DO)concentration level of 0.05 ppm. For stainless steels, the maximum Fen (15.35) is based, in part, on an assumed DO level of < 0.05 ppm. The staff questioned whether the assumed value of 0.05 ppm DO was a "bounding assumption." In a letter dated April 29, 2009 (ADAMS Accession No. ML091210104) the applicant provided additional information confirming the DO level's historically maintained at TMI-1 and also confirming the surveillance procedure for water chemistry sampling includes an administrative limit for DO of <0.05 ppm. Based on its review, the staff determined that this additional information was sufficient to close Cl 4.3.2-1. See SER Section 4.3.2.2 for additional information.

1.7 Summary

of Proposed License Conditions Following the staffs review of the LRA, including subsequent information and clarifications provided by the applicant, the staff identified two proposed license conditions. The first license condition requires the applicant to include the UFSAR supplement required by 10 CFR 54.21(d) in the next UFSAR update required by 10 CFR 50.71(e) following the issuance of the renewed license.The second license condition requires the applicant to complete the commitments in the UFSAR supplement, and notify the NRC in writing when implementation of those activities required prior to the period of extended operations are complete and can be verified by NRC inspection. 1-8 1.6 Summary of Confirmatory Items Following the staff's review of the LRA, including additional information and clarifications submitted through June 29, 2009, the staff closed previous confirmatory item (CI) 4.3.2-1 identified in the "Safety Evaluation Report With Open Items Related to the License Renewal of Three Mile Island Nuclear Station Unit 1" (ADAMS Accession No. ML09071 0604). The staff has identified no other confirmatory items. An item would be considered confirmatory if the staff and the applicant reached a satisfactory resolution, but the resolution had not been formally' submitted to the staff. In closed CI 4.3.2-1 the staff noted that the maximum Fen values for carbon steels and low alloy steels (1.74,2.455, respectively) are based, in part, onan assumed dissolved oxygen (DO) concentration level of 0.05 ppm. For stainless steels, the maximum Fen (15.35) is based, in part, on an assumed DO level of < 0.05 ppm. The staff questioned whether the assumed value of 0.05 ppm DO was a "bounding assumption." In a letter dated April 29, 2009 (ADAMS Accession No. ML091210104) the applicant provided additional information confirming the IDO level's historically maintained at TMI-1 and also confirming the surveillance procedure for water chemistry sampling includes ari administrative limit for DO of <0.05 ppm. Based on its review, the staff determined that this additional information was sufficient to close CI 4.3.2-1. See SER Section 4.3.2.2 for additional information.

1.7 Summary

of Proposed License Conditions Following the staff's review of the LRA, including subsequent information and clarifications provided by the applicant, the staff identified two proposed license conditions. The first license condition requires the applicant to include the UFSAR supplement required by 10 CFR 54.21(d) in the next UFSAR update required by 10 CFR 50.71(e) following the issuance of the renewed license .. The second license condition requires the applicant to complete the commitments in the UFSAR supplement, and notify the NRC in writing when implementation of those activities required prior to the period of extended operations are complete and can be verified by NRC inspection. 1-8 SECTION 2 STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW 2.1 Scoping and Screening Methodology

2.1.1 Introduction

Title 10, Section 54.21, "Contents of Application-Technical Information," of the Code of Federal Regulations (10 CFR 54.21) 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 structures, systems, and components (SSCs) within the scope of license renewal.LRA Section 2.1, "Scoping and Screening Methodology," describes the methodology for identifying SSCs at the Three Mile Island Nuclear Station, Unit 1, (TMI-1) within the scope of license renewal and SCs subject to an AMR. The staff reviewed the scoping and screening methodology of AmerGen Energy Company, LLC (AmerGen 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 54-The License Renewal Rule," dated June 2005. The applicant also considered the correspondence between the staff, other applicants, and NEI.2.1.2 Summary of Technical Information in the Application LRA Sections 2 and 3 state the technical information required by 10 CFR 54.4, "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.LRA Section 2.1, describes the process used to identify the SSCs that meet the license renewal scoping criteria under 10 CFR 54.4(a), and the process used to identify the SCs that are subject to an AMR, as required by 10 CFR 54.21(a)(1). Additionally, LRA Section 2.2 "Plant Level Scoping Results," Section 2.3 "Scoping and Screening Results: Mechanical," Section 2.4"Scoping and Screening Results: Structural," and Section 2.5 "Scoping and Screening Results: Electrical Systems/Commodity Groups," provided the results of the process used to identify the SCs that are subject to an AMR. LRA Section 3.0, "Aging Management Review Results," contains the following information: Section 3.1 "Aging Management of Reactor Vessel, Internals and Reactor Coolant System," Section 3.2 "Aging Management of Engineered Safety Features Systems," Section 3.3 "Aging Management of Auxiliary Systems," Section 3.4 "Aging Management of Steam and Power Conversion System," Section 3.5 "Aging Management of Containment, Structures and Component Supports," and Section 3.6 "Aging Management of 2-1 SECTION 2 STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW 2.1 Scoping and Screening Methodology

2.1.1 Introduction

Title 10, Section 54.21, "Contents of Application-Technical Information," of the Code of Federal Regulations (10 CFR 54.21) 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 structures, systems, and components (SSCs) within the scope of license renewal. .. lRA Section 2.1, "Scoping and Screening Methodology," describes the methodology for identifying SSCs at the Three Mile Island Nuclear Station, Unit 1, (TMI-1) within the scope of license renewal and SCs subject to an AMR. The staff reviewed the scoping and screening methodology of AmerGen Energy Company, llC (AmerGen 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 54-The License Renewal Rule," dated June 2005. The applicant also considered the correspondence between the staff, other applicants, and NEI. 2.1.2 Summary of Technical Information in the Application lRA Sections 2 and 3 state the technical information required by 10 CFR 54.4, "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. LRA Section 2.1, describes the process used to identify the SSCs that meet the license renewal scoping criteria under 10 CFR 54.4(a), and the process used to identify the SCs that are subject to an AMR, as required by 10 CFR 54.21(a)(1). Additionally, lRASection 2.2 "Plant level Scoping Results," Section 2.3 "Scoping and Screening Results: Mechanical," Section 2.4 "Scoping and Screening Results: Structural," and Section 2.5 "Scoping and Screening Results: Electrical Systems/Commodity Groups," provided the results of the process used to identify the SCs that are subject to an AMR. lRA Section 3.0, "Aging Management Review Results," contains the following information: Section 3.1 "Aging Management of Reactor Vessel, Internals and Reactor Coolant System," Section 3.2 "Aging Management of Engineered Safety Features Systems," Section 3.3 "Aging Management of Auxiliary Systems," Section 3.4 "Aging Management of Steam and Power Conversion System," Section 3.5 "Aging Management of Containment, Structures and Component Supports," and Section 3.6 "Aging Management of 2-1 Electrical Commodity Groups." LRA Section 4 "Time-Limited Aging Analyses (TLAA)," contains the applicant's identification and evaluation of 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 Section 2.1, "Scoping and Screening Methodology," of NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants," Revision I (SRP-LR). The following regulations form the basis for the acceptance criteria for the scopinrg and screening methodology review:* 10 CFR 54.4(a), as it relates to the identification of plant SSCs within the scope of theI'Rule 10 CFR 54.4(b), as it relates to the identification of the intended functions of SSCs within the scope of the Rule 10 CFR 54.21(a)(1) and (a)(2), as they relate to the methods utilized by the applicant to identify plant SCs subject to an AMR As part of the review of the applicant's scoping and screening methodology, the staff reviewed the activities described in the following sections of the LRA using the guidance contained in the SRP-LR: " Section 2.1.5, to ensure that the applicant described a process for identifying the SSCs within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)* Section 2.1.6, to ensure that the applicant described a process for determining the SCs that are subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1) and (a)(2)In addition, the staff conducted a scoping and screening methodology audit at TMI-1 during the week of May 19-22, 2008. 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 the implementation of project level guidelines and topical reports describing the applicant's scoping and screening methodology. The staff conducted detailed discussions with the applicant on the implementation and control of the license renewal program and reviewed the administrative control documentation used by the applicant during the scoping and screening process, the quality practices used by the applicant to develop the LRA, and the training and qualification program of the LRA development team. The staff evaluated the quality attributes of the applicant's aging management program (AMP) activities described in Appendix A, "Final Safety Analysis Report Supplement," and Appendix B, "Aging Management Programs," of the LRA. The staff also reviewed the training and qualifications of the LRA development team. On a sampling basis, the staff performed a review of the main steam system, the decay heat removal system, the turbine building, and the intermediate building, including a review of the scoping and 2-2 Electrical Commodity Groups." LRA Section 4 "Time-Limited Aging Analyses (TLAA)," contains the applicant's identification and evaluation of TLAAs. 2.1.3 Scoping and Screening Program Review The staff evaluated the LRAscoping and screening methodology in accordance with the guidance contained in Section 2.1, "Scoping and Screening Methodology," of NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants," Revisi6n 1 (SRP-LR). The following regulations form the basis for the acceptance criteria for the and screening methodology review:

  • 10 CFR 54.4(a), as it relates to the identification of plant SSCs within the scope of the Rule
  • 10 CFR 54.4(b), as it relates to the identification of the intended functions of SSCs within the scope of the Rule .
  • 10 CFR 54.21 (a)( 1) and (a )(2), as they relate to the methods utilized by the applicant to identify plant SCs subject to an AMR As part of the review of the applicant's scoping and screening methodology, the staff reviewed the activities described in the following sections of the LRA using the guidance contained in the SRP-LR:
  • Section 2.1.5, to ensure that the applicant described a process for identifying the SSCs within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)
  • Section 2.1.6, to ensure thatthe applicant described a process for determining the SCs that are subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1) and (a)(2) In Cilddition, the staff conducted a scoping and screening methodology audit at TMI-1 during the week of May 19-22, 2008. The audit focused on ensuring that the applicant had developed and implemented adequate guidance to conduct the scoping and screening of SSCs in accorda'hce with the methodologies described in the LRA and the requirements of the Rule. The staff ' reviewed the implementation of project level guidelines and topical reports describing the applicant's scoping and screening methodology.

The staff conducted detailed discussions with the applicant on the implementation and control of the license renewal program and reviewed the administrative control documentation used by the applicant during the scoping and screening process, the quality practices used by the applicant to develop the LRA, and the training and qualification program of the LRA development team. The staff evaluated the quality attributes of the applicant's aging management program (AMP) activities described in Appendix A, "Final Safety Analysis Report Supplement," and Appendix B, "Aging Management Programs," of the LRA. The staff also reviewed the training and qualifications of the LRA development team. On a sampling basis, the staff performed a review* of the main steam system, the decay heat removal system, the turbine building, and the intermediate building, including a review of the scoping and 2-2 screening results reports and the supporting design documentation used to develop the reports.This review was performed to ensure that the applicant had appropriately implemented the methodology outlined in the administrative controls and to verify that the results were consistent with the current licensing basis (CLB) documentation. 2.1.3.1 Implementing Procedures and Documentation Sources Used for Scoping and Screening The staff reviewed the applicant's scoping and screening implementing procedures as documented in the Scoping and Screening Methodology Audit report, dated December 3, 2008, (ADAMS Accession No. ML083240245) to verify that the process used to identify SCs subject to an AMR was consistent with the SRP-LR. Additionally, the staff reviewed the scope of CLB documentation sources and the process used by the applicant to ensure that the applicant's commitments, as documented in the CLB and relative to the requirements of 10 CFR 54.4 and 10 CFR 54.21, were appropriately considered and that the applicant adequately implemented its procedural guidance during the scoping and screening process.2.1.3.1.1 Summary of Technical Information in the Application In LRA Section 2.1, the applicant addressed the following information sources for the license renewal scoping and screening process:* Updated Final Safety Analysis Report (UFSAR)* Preliminary safety analysis report* Fire hazards analysis report* Environmental qualification master list* Design basis documents* Maintenance rule information

  • Controlled plant component database* Plant drawings* Docketed correspondence The applicant stated that it used this information to identify the functions performed by plant systems and structures.

It then compared these functions to the scoping criteria in 10 CFR 54.4(a)(1 )-(3) to determine if the associated plant system or structure performed a licenserenewal intended function. It also used these sources to develop the list of SCs subject to an AMR.2.1.3.1.2 Staff Evaluation Scopinq and Screening Implementation Procedures. The staff reviewed the applicant's scoping and screening methodology implementation procedures, including license renewal guidelines, documents, reports, and AMR reports, to ensure the guidance was consistent with the requirements of the Rule, the SRP-LR, and NEI 95-10. The staff finds the overall process used toimplement 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 applicant's 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. During the 2-3 screening results reports and the supporting design documentation used to develop the reports. This review was performed to ensure that the applicant had appropriately implemented the methodology outlined in the administrative controls and to verify that the results were consistent with the current licensing basis (CLB) documentation. 2.1.3.1 Implementing Procedures and Documentation Sources Used for Scoping and Screening The staff reviewed the applicant's scoping and screening implementing procedures as documented in the Scoping and Screening Methodology Audit report, dated December 3, 2008, (ADAMS Accession No. ML083240245) to verify that the process used to identify SCs subject to an AMR was consistent with the SRP-LR. Additionally, the staff reviewed the scope of CLB documentation sources and the process used by the applicant to ensure that the applicant's commitments, as documented in the CLB and relative to the requirements of 1.0 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 Report (UFSAR)
  • Preliminary safety analysis report
  • Fire hazards analysis report
  • Environmental qualification master list
  • Design basis documents
  • Maintenance rule information
  • Controlled plant component database
  • Plant drawings
  • Docketed correspondence The applicant stated that it used this information to identify the functions performed by plant systems and structures.

It then compared these functions to the scoping criteria in 10 CFR 54.4(a)(1 )-(3) to determine if the associated plant system or structure performed a license renewal intended function. It also used these sources to develop the list of SCs subject to an AMR. 2.1.3.1.2 Staff Evaluation Scoping and Screening Implementation Procedures. The staff reviewed the applicant's scoping and screening methodology implementation procedures, including license renewal guidelines, documents, reports, and AMR reports, to ensure the guidance was consistent with the requirements of the Rule, the SRP-LR, and NEI 95-10. The staff finds 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 applicant's 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. During the 2-3 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 the NRC the staff position concerning what SSCs meet the 10 CFR 54.4(a)(2) criterion, which is documented in the SRP-LR.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 LIRA activities. Sources of Current Licensinq Basis Information. During the audit, the staff reviewed the scope and depth of the applicant's CLB review to verify that the methodology is sufficiently comprehensive to identify SSCs within the scope of license renewal, as well as SCs requiring an AMR. Pursuant to 10 CFR 54.3(a), the CLB is the set of NRC requirements applicable to a specific plant and a licensee's written commitments for ensuring compliance with, and operation within, applicable NRC requirements and the plant-specific design bases that are docketed and in effect. The CLB includes certain NRC regulations, orders, license conditions, exemptions, i Technical Specifications, design-basis information (documented in the most recent Updated Final Safety Analysis Report [UFSAR]). 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 UFSAR, license renewal boundary diagrams, design basis documents, and maintenance rule information. In addition, the applicant identified additional potential sources of plant information pertinent to the scoping and screening process, including preliminary safety analysis report, fire hazards analysis report, environmental qualification master list, controlled plant component database, plant drawings, and docketed correspondence. The staff confirmed that the applicant's detailed license renewal program guidelines specified the use of the CLB source information in developing scoping evaluations. The TMI-1 component record list (CRL) and the maintenance rule information were the applicant's primary repository for component safety classification information. During the audit, the staff reviewed the applicant's administrative controls for the CRL. These controls are described, and implementation is governed, by plant administrative procedures. Based on a review of the administrative controls and a sample of the system classification information contained in applicable plant documentation, the staff concludes that the applicant has established adequate measures to control the integrity and reliability of its safety classification data, and therefore, the staff concludes that the information sources used by the applicant during the scoping and 1, screening process have provided a sufficiently controlled source of system and componentý data to support scoping and screening evaluations. During the staff's review of the applicant's CLB evaluation process, the applicant explained the incorporation of updates to the CLB and the process used to ensure those updates are adequately incorporated into the license renewal process. The staff determined that Section 2.1 of the LRA provided a description of the CLB and related documents used during the scoping and screening process that is consistent with the guidance contained in the SRP-LR.In addition, the staff reviewed the implementing procedures and results reports used to supportidentification of SSCs relied on to demonstrate compliance with the safety-related criteria, 2-4 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 the NRC the staff position concerning what SSCs meet the 10 CFR 54.4(a)(2) criterion, which is in the SRP-LR. 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. During the audit, the staff reviewed the scope and depth of the applicant's CLB review to verify that the methodology is sufficiently comprehensive to identify SSCs within the scope of license renewal, as well as SCs requiring an AMR. Pursuant to 10 CFR 54.3(a), the CLB is the set of NRC requirements applicable to a specific plant and a licensee's written commitments for ensuring compliance with, and within, applicable NRC requirements and the plant-specific design bases that are docketed and in effect. The CLB includes certain NRC regulations, orders, license conditions, exemptions, i, Technical Specifications, design-basis information (documented in the most recent Final Safety Analysis Report [UFSAR]). 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 UFSAR, license renewal boundary diagrams, design basis documents, and maintenanqe rule information. In addition, the applicant identified additional potential sources of plant information pertineht to the scoping and screening process, including preliminary safety analysis report, fire hazards analysis report, environmental qualification master list, controlled plant component database, plant drawings, and docketed correspondence. The staff confirmed that the applicant's detailed license renewal program guidelines specified the use of the CLB source information in developing scoping evaluations. The TMI-1 component record list (CRL) and the maintenance rule information were the applicant's primary repOSitory for component safety classification information. During the audit, the staff reviewed the applicant's administrative controls for the CRL. These controls are described, and implementation is governed, by plant administrative procedures. Based on a review of the administrative controls and a sample of the system classification information contained in applicable plant documentation, the staff concludes that the applicant has established adequate measures to control the integrity and reliability of its safety classification data, and therefore, the staff concludes that the information sources used by the applicant during the scoping and :i screening process have provided a sufficiently controlled source of system and component:, data to support scoping and screening evaluations. ' During the staffs review of the applicant's CLB evaluation process, the applicant explained the incorporation of updates to the CLB and the process used to ensure those updates are adequately incorporated into the license renewal process. The staff determined that Section 2.1 of the LRA provided a description of the CLB and related documents used during the scoping and screening process that is consistent with the guidance contained in the SRP-LR. I In addition, the staff reviewed the implementing procedures and results reports used to sup'port identification of SSCs relied on to demonstrate compliance with the safety-related criteria, ' 2-4 nonsafety-related criteria, and the regulated events criteria pursuant to 10 CFR 54.4(a). The applicant's license renewal program guidelines provided a comprehensive listing of documents used to support scoping and screening evaluations. The staff finds these design documentation sources to be useful for ensuring that the initial scope of SSCs identified by the applicant was consistent with the plant's CLB.2.1.3.1.3 Conclusion Based on its review of LRA Section 2.1, the detailed scoping and screening implementation procedures, and the results from the scoping and screening audit, the staff concludes that the applicant's scoping and screening methodology considers CLB information consistently with the Rule, the SRP-LR and the NEI 95-10 guidance and, therefore, is acceptable. 2.1.3.2 Quality Controls Applied to LRA Development2.1.3.2.1 Staff EvaluationThe staff reviewed the applicant's quality assurance (QA) controls to ensure that scoping and screening methodologies used in the LRA were adequately implemented. The applicant applied the following QA processes during the LRA development:

  • The scoping and screening methodology was governed by written procedures and guidelines.
  • The LRA was examined by the applicant's team in a structured self assessment.
  • The LRA was examined by internal assessment teams, including a challenge board, plant oversight review committee, nuclear oversight team, and a nuclear safety review board.Each of these teams included different levels of plant and organizational management.

The LRA was examined by external assessment teams, including peer reviews. Additional benchmarking was also done of recent license renewal applicants.

  • Comments received through the assessment process were addressed and managed by peer and management review.The audit team reviewed the applicant's focused area self assessment (FASA) and a sample comment resolution table and determined that the applicant's comment resolution process is consistent and adequate.2.1.3.2.2 Conclusion On the basis of its review of pertinent LRA development guidance, discussion with the applicant's license renewal staff, and a review of the applicant's documentation of the activities performed to assess the quality of the LRA, the staff concludes that the applicant's QA activities meet current regulatory requirements and provide additional assurance that LRA development activities were performed in accordance with the applicant's license renewal program requirements.

2-5 nonsafety-related criteria, and the regulated events criteria pursuant to 10 CFR 54.4(a). The applicant's license renewal program guidelines provided a comprehensive listing of documents used to support scoping and screening evaluations. The staff finds these design documentation sources to be useful for ensuring that the initial scope of SSCs identified by the applicant was consistent with the plant's CLB. 2.1.3.1.3 Conclusion Based on its review of LRA Section 2.1, the detailed scoping and screening implementation procedures, and the results from the scoping and screening audit, the staff concludes that the applicant's scoping and screening methodology considers CLB information consistently with the Rule, the SRP-LR and the NEI 95-10 guidance and, therefore, is acceptable. 2.1.3.2 Quality Controls Applied to LRA Development 2.1.3.2.1 Staff Evaluation The staff reviewed the applicant's quality assurance (QA) controls to ensure that scoping and screening methodologies used in the LRA were adequately implemented. The applicant applied the following QA processes during the LRA development:

  • The scoping and screening methodology was governed by written procedures and guidelines.
  • The LRA was examined by the applicant's team in a structured self assessment.
  • The LRA was examined by internal assessment teams, including a challenge board, plant oversight review committee, nuclear oversight team, and a nuclear safety review board. Each of these teams included different levels of plant and organizational management.
  • The LRA was examined by external assessment teams, including peer reviews. Additional benchmarking was also done of recent license renewal applicants.
  • Comments received through the assessment process were addressed and managed by peer and management review. The audit team reviewed the applicant's focused area self assessment (FASA) and a sample comment resolution table and determined that the applicant's comment resolution process is consistent and adequate.

2.1.3.2.2 Conclusion On the basis of its review of pertinent LRA development guidance, discussion with the applicant's license renewal staff, and a review of the applicant's documentation of the activities performed to assess the quality of the LRA, the staff concludes that the applicant's QA activities meet current regulatory requirements and provide additional assurance that LRA development activities were performed in accordance with the applicant's license renewal program requirements. 2-5 2.1.3.3 Training 2.1.3.3.1 Staff Evaluation The staff reviewed the applicant's training process to ensure the guidelines and methodology for the scoping and screening activities were applied in a consistent and appropriate manner. As outlined in the implementing documents, the applicant required training for all personnel participating in the development of the LRA and used only trained and qualified personnel to prepare the scoping and screening implementing procedures. The training included the following activities:

  • Training was required for the license renewal project personnel and followed documented, written guidance.* Initial qualification was completed before the project started and included the review of thelicense renewal process, license renewal project guidance, and relevant industry documents such as 10 CFR Part 50 regulations; NEI 95-10; Regulatory Guide 1.188; the SRP-LR; and NUREG-1 801 Revision 1, "Generic Aging Lessons Learned Report."* Classroom training featured classroom training sessions on topics such as site documentation overview, systems and structures overview, system specific training,,, and database training.* Phase training included the review of processes and procedures for the preparation of the basis documents." Biweekly training featured meetings where discussions were held to educate the applicant's personnel on current and emerging issues pertaining to the preparation and handling of the LRA.2.1.3.3.2 Conclusion On the basis of discussions with the applicant's license renewal project personnel responsible for the scoping and screening process, and the staffs review of selected documentation in support of the process, the staff concludes that the applicant's personnel were adequately trained to implement the scoping and screening methodology as described in the applicant's implementing documents and the LRA.2.1.3.4 Scoping and Screening Program Review Conclusion On the basis of its review of information provided in Section 2.1 of the LRA, and its review of the applicant's detailed scoping and screening implementing procedures, QA controls applied, the applicant's training process, the results from the scoping and screening audit, and discussions with the applicant's license renewal personnel, the staff concludes that the applicant's scoping and screening program is consistent with the SRP-LR and the requirements of 10 CFR Part 54, and, therefore, is acceptable.

2-6 2.1.3.3 Training 2.1.3.3.1 Staff Evaluation The staff reviewed the applicant's training process to ensure the guidelines and methodology for the scoping and screening activities were applied in a consistent and appropriate manner. As outlined in the implementing documents, the applicant required training for all personnel participating in the development of the LRA and used only trained and qualified personnel to prepare the scoping and screening implementing procedures. The training included the follbwing activities:

  • Training was required for the license renewal project personnel and followed documented, written guidance.
  • Initial qualification was completed before the project started and included the review of the license renewal process, license renewal project guidance, and relevant industry documents such as 10 CFR Part 50 regulations; NEI 95-10; Regulatory Guide 1.188; the SRP-LR; and NUREG-1801 Revision 1, "Generic Aging Lessons Learned Report."
  • Classroom training featured classroom training sessions on topics such as site documentation overview, systems and structures overview, system specific training,!.

and database training. .

  • Phase training included the review of processes and procedLires for the preparation of the basis documents.
  • Biweekly training featured meetings where discussions were held to educate the applicant's personnel on current and emerging issues pertaining to the preparation and handling of the LRA. 2.1.3.3.2 Conclusion On the basis of discussions with the applicant's license renewal project personnel for the scoping and screening process, and the staff's review of selected documentation in sup'port of the process, the staff concludes that the applicant's personnel were adequately trained to implement the scoping and screening methodology as described in the applicant's implementing documents and the LRA. 2.1.3.4 Scoping and Screening Program Review Conclusion On the basis of its review of information provided in Section 2.1 of the LRA, and its review of the applicant's detailed scoping and screening implementing procedures, QA controls applied, the applicant's training process, the results from the scoping and screening audit, and discussions with the applicant's license renewal personnel, the staff concludes that the applicant's scoping and screening program is consistent with the SRP-LR and the requirements of 10 CFR Part 54, and, therefore, is acceptable.

2-6

2.1.4 Plant

Systems, Structures, and Components Scoping Methodology LRA Section 2.1 describes the applicant's methodology used to scope SSCs pursuant to the requirements of the 10 CFR 54.4(a) scoping criteria. The applicant described the scoping process for the plant in terms of systems and structures. Specifically, the applicant developed a list of plant systems and structures, identified their intended functions, and determined which functions meet one or more of the three criteria of 10 CFR 54.4(a). The scoping evaluations were documented in a System and Structure Scoping Report. If any portion of a system or structure met the scoping criteria of 10 CFR 54.4, the system or structure was included within the scope of license renewal. Mechanical systems and structures were then further evaluated to determine those mechanical and structural components that perform or support the identified intendedfunctions. The in-scope boundaries of mechanical systems and structures were developed and depicted on license renewal boundary drawings. Electrical and I&C components contained within in-scope electrical or mechanical systems were included within the scope of license renewal regardless of function.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 2.1.5.1, "Safety-Related-10 CFR 54.4(a)(1)," describes the scoping methodology as it relates to the safety-related criterion in accordance with 10 CFR 54.4(a)(1 ). The safety-related systems and structures were identified in the CRL.The applicant stated that the safety-related classifications in the CRL were established using a controlled procedure and that the classification criteria differences relative to 10 CFR 54.4(a)(1) were evaluated in a license renewal basis document and accounted for during the license renewal scoping process. Safety-related classifications for systems and structures were based on system and structure descriptions and analyses in the UFSAR or design basis documents. Systems and structures identified as safety-related in the UFSAR, in design basis documents, or in the CRL were included within the scope of license renewal in accordance with 10 CFR 54.4(a)(1). The applicant confirmed that it considered all plant conditions, including conditions of normal operation, anticipated operational occurrences, design basis accidents, 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 upon to remain functional during and following a design basis event (DBE) to ensure the following functions: (i) the integrity of the reactor coolant pressure boundary; (ii) the capability to shut down the reactor and maintain it in a safe shutdown condition; or (iii) the capability to prevent or mitigate the consequences of accidents that could result in potential offsite exposures comparable to those referred to in 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or Part 100.11 of the Code of Federal Regulations. With regard to identification of DBEs, Section 2.1.3, "Review Procedures," of the SRP-LR states: The set of DBEs as defined in the Rule is not limited to Chapter 15 (or equivalent) of the UFSAR. Examples of DBEs that may not be described in this chapter include external events, such as floods, storms, earthquakes, tornadoes, or hurricanes, and internal events, 2-7 2.1.4 Plant Systems, Structures, and Components Scoping Methodology LRA Section 2.1 describes the applicant's methodology used to scope SSCs pursuant to the requirements of the 10 CFR 54.4(a) scoping criteria. The applicant described the seoping process for the plant in terms of systems and structures. Specifically, the applicant developed a list of plant systems and structures, identified their intended functions, and determined which functions meet one or more of the three criteria of 10 CFR 54.4(a). The scoping evaluations were documented in a System and Structure Scoping Report. If any portion of a system Or structure met the scoping criteria of 10 CFR 54.4, the system or structure was included within the scope of license renewal. Mechanical systems and structures were then further evaluated to determine those mechanical and structural components that perform or support the identified intended . functions. The in-scope boundaries of mechanical systems and structures were developed and depicted on license renewal boundary drawings. Electrical and I&C components contained within in-scope electrical or mechanical systems were included within the scope of license renewal regardless of function. . 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 2.1.5.1, "Safety-Related-10 CFR 54.4(a)(1 )," describes the scoping methodology as it relates to the safety-related criterion in accordance with 10 CFR 54.4( a)( 1). The safety-related systems and structures were identified in the CRL. The applicant stated that the safety-related classifications in the CRL were established using a controlled procedure and that the classification criteria differences relative to 10 CFR 54.4(a)(1) were evaluated in a license renewal basis document and accounted for during the license renewal scoping process. Safety-related classifications for systems and structures were based on system and structure descriptions and analyses in the UFSARor design basis documents. Systems and structures identified as safety-related in the UFSAR, in design basis documents, or in the CRL were included within the scope of license renewal in accordance with 10 CFR 54.4(a)(1). The applicant confirmed that it considered all plant conditions, including conditions of normal operation, antiCipated operational occurrences, design basis accidents, 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 upon to remain functional during and following a design basis event (DBE) to ensure the following functions: (i) the integrity of the reactor coolant pressure boundary; (ii) the capability to shut down the reactor and maintain it in a safe shutdown condition; or (iii) the capability to prevent or mitigate the consequences of accidents that could result in potential offsite exposures comparable to those referred to in 1 OCFR 50.34(a)(1), 10 CFR 50.67(b)(2), or Part 100.11 of the Code of Federal Regulations. With regard to identification of DBEs, Section 2.1.3, "Review Procedures," of the SRP-LR states: The set of DBEs as defined in the Rule is not limited to Chapter 15 (or equivalent) of the UFSAR. Examples of DBEs that may not be described in this chapter include external events, such as floods, storms, earthquakes, tornadoes, or hurricanes, and internal events, 2-7 such as a high energy line break. Information regarding DBEs as defined in 10 CFR 50.49(b)(1) may be found in any chapter of the facility UFSAR, the Commission's regulations, NRC orders, exemptions, or license conditions within the CLB. These sources should also be reviewed to identify SSCs relied upon to remain functional during and following DBEs (as defined in 10 CFR 50.49(b)(1)) to ensure the functions described in 10 CFR 54.4(a)(1). During the audit, the applicant stated that it evaluated the applicable types of events listed in NEI 95-10 (i.e., anticipated operational occurrences, DBAs, external events, and natural phenomena). The staff reviewed the applicant's basis documents that described all design basis conditions in the CLB and addressed all events defined by 10 CFR 50.49(b)(1) and 10 CFR 54.4(a)(1). The staff noted that the UFSAR and basis documents discussed events such as internal and external flooding, tornados, and missiles. The staff determined that the applicant's evaluation of DBEs was consistent with 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 applicant's evaluation of safety-related SSCs, and sampled the applicant's 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 applicant's personnel whowere responsible for these evaluations. The staff reviewed the applicant's evaluation of the Rule and CLB definitions pertaining to 10 CFR 54.4(a)(1) and determined that TMI-ls CLB definition of "safety-related" referred to 10 CFR 50.67 (for loss-of-coolant accident (LOCA) and fuel handling accident (FHA) analyses)and to 10 CFR 100, for all other accidents. The applicant stated that the definition did not contain references to 10 CFR 50.34 as specified in the Rule since 10 CRF 50.34(a)(1) is only applicable to facilities seeking a construction permit. The applicant's definition of "safety-related" and ýexceptions to the definition in the Rule are documented in LRA Section 2.1.3.2. Based on its review, the staff verified that 10 CFR 50.34(a)(1 ) is in fact, not applicable, since it concerns applicants for a construction permit. The staff determined that 10 CFR 50.67(b)(2), which concerns the use of an alternate source term in the dose analysis, is applicable as described in the loss of coolant and fuel handling accident analyses, and was adequately addressed during the scoping process.The staff reviewed a sample of the license renewal scoping results for the main steam system, decay heat removal system, the turbine building, and the intermediate building to provide additional assurance that the applicant adequately implemented its scoping methodology with respect to 10 CFR 54.4(a)(1). The staff confirmed 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. The staff also confirmed that the applicant had identified and used pertinent engineering and licensing information to identify the SSCs required to be in scope in accordance with the 10 CFR 54.4(a)(1) criteria.2-8 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 facilityUFSAR, the Commission's regulations, NRC orders, exemptions, or license conditions within the CLB. These sources should also be reviewed to identify SSCs relied upon to remain functional during and following DBEs (as defined in 10 CFR 50.49(b)( 1)) to ensure the functions described in 10 CFR 54.4(a)(1). During the audit, the applicant stated that it evaluated the applicable types of events listed i'n NEI 95-10 (Le., anticipated operational occurrences, DBAs, external events, and natural phenomena). The staff reviewed the applicant's basis documents that described all design basis conditions in the CLB and addressed all events defined by 10 CFR 50.49(b)(1) and 10 CFR 54.4(a)(1). The staff noted that the UFSAR and basis documents discussed events such as internal and external flooding, tornados, and missiles. The staff determined that the applicant's evaluation of DBEs was consistent with 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, 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 applicant's evaluation of safety-related SSCs, and sampled the applicant's 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 applicant's personnel who were responsible for these evaluations. The staff reviewed the applicant's evaluation of the Rule and CLB definitions pertaining to 10 CFR 54.4(a)(1) and determined that TM/-1 s CLB definition of "safety-related" referred to 10 CFR 50.67 (for loss-of-coo/ant accident (LOCA) and fuel handling accident (FHA) analyses) and to 10 CFR 100, for all other accidents. The applicant stated that the definition did not references to 10 CFR 50.34 as specified in the Rule since 10 CRF 50.34(a)(1) is only applicable to facilities seeking a construction permit. The applicant's definition of "safety-related" and exceptions to the definition in the Rule are documented in LRA Section 2.1.3.2. Based on its reView, the staff verified that 10 CFR 50.34(a)(1) is in fact, not applicable, since it concerns applicants for a construction permit. The staff determined that 10 CFR 50.67(b )(2), which concerns the use of an alternate source term in the dose analysis, is applicable as described in the loss of coolant and fuel handling accident analyses, and was adequately addressed during the scoping process. The staff reviewed a sample of the license renewal scoping results for the main steam system, decay heat removal system, the turbine building, and the intermediate building to provide I additional assurance that the applicant adequately implemented its scoping methodology respect to 10 CFR 54.4(a)(1). The staff confirmed that the applicant developed the scoping::results for each of the sampled systems consistently with the methodology, identified the SSCs crJdited for performing intended functions, and adequately described the basis for the results as weil as the intended functions. The staff also confirmed that the applicant had identified and used pertinent engineering and licensing information to identify the SSCs required to be in scope in accordance with the 10 CFR 54.4(a)(1) criteria. 2-8 2.1.4.1.3 Conclusion On the basis of its review of systems (on a sampling basis), discussions with the applicant, and a review of the applicant's scoping process, the staff concludes that the applicant's methodology for identifying systems and structures is consistent with the SRP-LR and 10 CFR 54.4(a)(1), and, therefore, is acceptable. 2.1.4.2 Application of the Scoping Criteria in 10 CFR 54.4(a)(2) 2.1.4.2.1 Summary of Technical Information in the Application LRA Section 2.1.5.2, "Nonsafety-Related Affecting Safety-Related--10 CFR 54.4(a)(2)," describes the applicant's scoping methodology as it relates to the nonsafety-related criteria in 10 CFR 54.4(a)(2). The applicant's 10 CFR 54.4(a)(2) scoping methodology was based 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 10 CFR 54.4(a)(2) criteria.Functional Support for Safety-Related SSC 10 CFR 54.4(a)(1) Functions. LRA Section 2.1.5.2 states that nonsafety-related SSCs required to perform a function in support of safety-related components are included within the scope of license renewal in accordance with 10 CFR 54.4(a)(1 ). The staff finds that for the nonsafety-related systems and structures required to remain functional to support a safety function, the systems and structures were included within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2). Connected to and Provide Structural Support for Safety-Related SSCs. LRA Section 2.1.5.2 states that for a nonsafety-related piping systems connected to a safety-related piping system, the nonsafety-related system was assumed to provide structural support to the safety-related system, unless otherwise confirmed by a review of the installation details. The applicant stated that the entire nonsafety-related system was included in scope for 10 CFR 54.4(a)(2), up to one of the following: (1) A seismic anchor or at least two supports in each of three orthogonal directions. (2) A base-mounted component that is a rugged component and is designed not to impose loads on connecting piping.(3) A flexible connection that is considered a pipe stress analysis model end point when the flexible connection effectively decouples the piping system.(4) A free end of nonsafety-related piping.(5) A point where buried piping exits the ground.(6) For nonsafety-related piping runs that are connected at both ends to safety-related piping the entire run of nonsafety-related piping was included in scope.The applicant stated that the failure in the nonsafety-related piping beyond the above anchor or equivalent anchor locations would not impact structural support of the safety-related piping.2-9 2.1.4.1.3 Conclusion On the basis of its review of systems (on a sampling basis), discussions with the applicant, and a review of the applicant's scoping process, the staff concludes that the applicant's methodology for identifying systems and structures is consistent with the SRP-LR and 10 CFR 54.4(a)(1), and, therefore, is acceptable. 2.1.4.2 Application of the Scoping Criteria in 10 CFR 54.4(a)(2) 2.1.4.2.1 Summary of Technical Information in the Application LRA Section 2.1.5.2, "Nonsafety-Related Affecting Safety-Related-10 CFR 54.4(a)(2)," describes the applicant's scoping methodology as it relates to the nonsafety-related criteria in 10 CFR 54.4(a)(2). The applicant's 10 CFR 54.4(a)(2) scoping methodology was based 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 10 CFR 54.4{a)(2) criteria. Functional Support for Safety-Related SSC 10 CFR 54.4(a)( 1) Functions. LRA Section 2.1.5.2 states that nonsafety-related SSCs required to perform a function in support of safety-related components are included within the scope of license renewal in accordance with 10 CFR 54.4( a)( 1). The staff finds that for the nonsafety-related systems and structures required to remain functional to support a safety function, the systems and structures were included within the scope of license renewal in accordance with the requirements of 10 CFR 54.4{a)(2). Connected to and Provide Structural Support for Safety-Related SSCs. LRA Section 2.1.5.2 states that for a nonsafety-related piping systems connected to a safety-related piping system, the nonsafety-related system was assumed to provide structural support to the safety-related system, unless otherwise confirmed by a review of the installation details. The applicant stated that the entire nonsafety-related system was included in scope for 10 CFR 54.4(a)(2), up to one of the following: (1) A seismic anchor or at least two supports in each of three orthogonal directions. (2) A base-mounted component that is a rugged component and is designed not to impose loads on connecting piping. (3) A flexible connection that is considered a pipe stress analysis model end point the flexible connection effectively decouples the piping system. (4) A free end of nonsafety-related piping. (5) A point where buried piping exits the ground. (6) For nonsafety-related piping runs that are connected at both ends to safety-related piping the entire run of nonsafety-related piping was included in scope. The applicant stated that the failure in the nonsafety-related piping beyond the above anchor or equivalent anchor locations would not impact structural support of the safety-related piping. 2-9 Potential for Spatial Interactions with Safety-Related SSCs. LRA Section 2.1.5.2 states that nonsafety-related systems that are not connected to safety-related piping or components, or are beyond the first anchor, are within the scope of license renewal in accordance with 10 CFR 54.4(a)(2) if there is a potential for spatial interactions with safety-related equipment such that the failure of the nonsafety-related SSC could prevent the safety related SSC from performing its intended function. The staff notes that 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, overhead handling systems and mitigative features, such as pipe whip restraints, jet impingement shields, spray and drip shields, seismic supports, and flood barriers, are included 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 interactions. This scoping process, referred to as the "spaces" approach, involves an evaluation based on equipment location and the related SSCs and whether or not fluid-filled systemcomponents are located in the same space as safety-related equipment. A "space," for the purposes of the review, was defined as a structure containing active or passive safety-related SSCs.2.1.4.2.2 Staff Evaluation Pursuant to 10 CFR 54.4(a)(2), the applicant must consider all nonsafety-related SSCs, whose failure could prevent the satisfactory accomplishment of safety-related functions of SSCs relied on to remain functional during and following a DBE to ensure: (i) the integrity of the reactor coolant pressure boundary; (ii) the capability to shut down the reactor and maintain it in a safe shutdown condition; or (iii) the capability to prevent or mitigate the consequences of accidents that could result in potential offsite exposures comparable to those referred to in 10 CFR 50.34(a)(1), 10CFR 50.67(b)(2), or 10 CFR 100.11.NRC Regulatory Guide 1.188, "Standard Format and Content for Applications to Renew Nuclear Power Plant Operating Licenses," Revision 1 (Reg. Guide 1.188), endorses the use of NEI 95-10, Revision 6. NEI 95-10 describes the staff's position on 10 CFR 54.4(a)(2) scoping criteria, including nonsafety-related SSCs typically identified in the CLB; consideration of missiles, cranes, flooding and high energy line breaks; nonsafety-related SSCs connected to safety-related SSCs;nonsafety-related SSCs in proximity to safety-related SSCs, and mitigative and preventative options related to nonsafety-related and safety-related SSCs interactions. In addition, the staffs position (as discussed in NEI 95-10, Revision 6) is that the evaluation to determine which nonsafety-related SSCs are within scope should not consider hypothetical failures, but should, based on engineering judgment and operating experience, consider the likelihood of system failure during the extended period of operation. 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 2.1.5.2 in which the applicant described the scoping methodology for nonsafety-related SSCs pursuant to 10 CFR 54.4(a)(2). In addition, the staff reviewed the applicant's basis document and results report, which documents the guidance and corresponding results of the 2-10 Potential for Spatial Interactions with Safety-Related SSCs. LRA Section 2.1.5.2 states that nonsafety-related systems that are not connected to safety-related piping or components. or are beyond the first anchor. are within the scope of license renewal in accordance with 10 CFR 54.4(a)(2) if there is a potential for spatial interactions with safety-related equipmerit such that the failure of the nonsafety-related SSC could prevent the safety related SSC from performing its intended function. The staff notes that 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 related SSC. In addition. overhead handling systems and mitigative features. such as pipe whip restraints. jet impingement shields. spray and drip shields. seismic supports. and flood barriers. are included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The applicant used the preventive option described in NEI95-10. Appendix F. to determine the scope of license renewal with respect to the protection of 'safety-related SSCs from spatial interactions. This scoping process. referred to as the "spaces" approach. involves an evaluation based on equipment location and the related SSCs and whether or not fluid-filled system components are located in the same space as safety-related equipment. A "space." for the purposes of the review. was defined as a structure containing active or passive safety-related SSCs. 2.1.4.2.2 Staff Evaluation Pursuant to 10 CFR 54.4(a)(2). the applicant must consider all nonsafety-related SSCs. whose failure could prevent the satisfactory accomplishment of safety-related functions of SSCs relied on to remain functional during and following a DBE to ensure: (i) the integrity of the reactor coolant pressure boundary; (ii) the capability to shut down the reactor and maintain it if! a safe shutdown condition; or (iii) the capability to prevent or mitigate the consequences of accidents that could resultin potential offsite exposures comparable to those referred to in 10 CFR 50.34(a)(1). 10 CFR 50.67(b )(2). or 10 CFR1 00.11. NRC Regulatory Guide 1.188. "Standard Format and Content for Applications to Renew Nuclear Power Plant Operating Licenses." Revision 1 (Reg. Guide 1.188). endorses the use of NEI95-10. Revision 6. NEl95-10describes the staffs position on 10 CFR 54.4(a)(2) scoping criteria. including nonsafety-related SSCs typically identified in the CLB; consideration of missiles. cranes. flooding and high energy line breaks; nonsafety-related SSCs connected to safety-related SSCs; nonsafety-related SSCs in proximity to safety-related SSCs. and mitigative and preventative options related to nonsafety-related and safety-related SSCs interactions. In addition. the staffs position (as discussed in NEI 95-10. Revision 6) is that the evaluation to determine which nonsafety-related SSCs are within scope should not consider hypothetical failures. but should. based on engineering judgment and operating experience. consider the likelihood of system failure during the extended period of operation. 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 2.1.5.2 in which the applicant described the scoping methodology for nonsafety-related SSCs pursuant to 10 CFR 54.4(a)(2). In addition. the staff reviewed the applicant's basis document and results report. which documents the guidance and corresponding results of the 2-10 applicant's scoping review pursuant to 10 CFR 54.4(a)(2). The applicant stated that it performed this review in accordance with the guidance contained in NEI 95-10, Revision 6, Appendix F.Nonsafety-Related SSCs Required to Perform a Function that Supports a Safety-Related SSC. The staff determined that nonsafety-related SSCs required to remain functional to support a safety-related function were included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The applicant's scoping report discussed the evaluating criteria pursuant to 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 functions that support safety-related functions as required by 10 CFR 54.4(a)(2). Nonsafety-Related SSCs Directly Connected to Safety-Related SSCs. The applicant reviewed the safety-related to nonsafety-related interfaces for each mechanical system to identify the nonsafety-related components located between the safety-related to nonsafety-related interface and license renewal structural boundary. The applicant included the entire nonsafety-related system within the license renewal structural boundary within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). Based on its review, the staff determined that in order to identify the nonsafety-related SSCs connected to safety-related SSCs and required to be structurally sound to maintain the integrity of the safety-related SSCs, the applicant used a combination of the following to identify the portion of nonsafety-related piping systems to include within the scope of license renewal:* Seismic anchors.,* Equivalent anchors.* Bounding conditions described in NEI 95-10, Appendix F (base-mounted component, flexible connection, or inclusion of the entire piping run).* Approved design engineering evaluation and acceptance of an endpoint for scoping that provides documentation that piping beyond the scoping endpoint is not required for support of the safety-related piping components. During the audit, the staff reviewed the applicant's 10 CFR 54.4(a)(2) scoping methodology for attached piping, and the application of the methodology to an abandoned-in-place system (i.e., hydrogen purge system). The staff reviewed the scoping results for the abandoned hydrogen purge system and was not able to determine whether the applicant had applied the methods described in LRA Section 2.1.5.2 to determine the portion of the nonsafety-related piping, attached to safety-related SSCs, to be included within the scope of license renewal. In RAI 2.1.5.2-1, dated August 22, 2008, the staff requested the applicant provide additional information describing the methods used and the basis for conclusions, in determining the portion of nonsafety-related abandoned hydrogen purge discharge system piping, attached to safety-related SSCs, to be included within the scope of license renewal.In its response to the RAI dated September 8, 2008, the applicant stated that it had determined the boundary for the hydrogen purge systems had been incorrectly identified on the license renewal drawing. The applicant modified the boundary to include the appropriate portion of the nonsafety-related piping, attached to safety-related piping, required for structural support.2-11 applicant's scoping review to 10 CFR 54.4(a)(2). The applicant stated that it performed this review in accordance with the guidance contained in NEI 95-10, Revision 6, Appendix F. Nonsafety-Related SSCs Required to Perform a Function that Supports a Safety-Related SSC. The staff determined that nonsafety-related SSCs required to remain functional to support a safety-related function were included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The applicant's scoping report discussed the evaluating criteria pursuant to 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 functions that support safety-related functions as required by 10 CFR 54.4(a)(2). Nonsafety-Related SSCs Directly Connected to Safety-Related SSCs. The applicant reviewed the safety-related to nonsafety-related interfaces for each mechanical system to identify the nonsafety-related components located between the safety-related to nonsafety-related interface and license renewal structural boundary. The applicant included the entire nonsafety-related system within the license renewal structural boundary within the scope of license renewal in accordance with 10 CFR Based on its review, the staff determined that in order to identify the nonsafety-related SSCs connected to safety-related SSCs and required to be structurally sound to maintain the integrity of the safety-related SSCs, the applicant used a combination of the following to identify the pqrtion of nonsafety-related piping systems to include within the scope of license renewal:

  • Seismic anchors ..
  • Equivalent anchors.
  • Bounding conditions described in NEI 95-10, Appendix F (base-mounted component, flexible connection, or inclusion of the entire piping run).
  • Approved design engineering evaluation and acceptance of an endpoint for scoping that provides documentation that piping beyond the scoping endpoint is not required for support of the safety-related piping components.

During the audit, the staff reviewed the applicant's 10 CFR 54.4(a)(2) scoping methodology for attached piping, and the application of the methodology to an abandoned-in-place system (Le., hydrogen purge system). The staff reviewed the scoping results for the abandoned hydrogen purge system and was not able to determine whether the applicant had applied the methods described in LRA Section 2.1.5.2 to determine the portion of the nonsafety-related piping, attached to safety-related SSCs, to be included within the scope of license renewal. In RAI 2.1.5.2-1, dated August 22, 2008, the staff requested the applicant provide additional information describing the methods used and the basis for conclusions, in determining the portion of non safety-related abandoned hydrogen purge discharge system piping, attached to safety-related SSCs, to be included within the scope of license renewal. In its response to the RAI dated September 8, 2008, the applicant stated that it had determined the boundary for the hydrogen purge systems had been incorrectly identified on the license renewal drawing. The applicant modified the boundary to include the appropriate portion of the nonsafety-related piping, attached to safety-related piping, required for structural support. 2-11 Based on its review, the staff finds the applicant's response to RAI 2.1.5.2-1 acceptable because the applicant had reviewed the implementation of its methodology used to identify portions of abandoned, nonsafety-related SSCs attached to safety-related SSCs to be included within the scope of license renewal and had identified and included the required portions of the nonsafety-related SSCs. The staffs concern described in RAI 2.1.5.2-1 is resolved.During the audit, the staff noted the applicant had not clearly defined scoping endpoints for three attached piping segments in the make-up and purification system (license renewal drawing: LR-302-661, Revision 0 for piping connected to valves MU-V1 11, MU-V27, and MU-V41) because the piping was inaccessible at power. In RAI 2.1.5.2-2, the staff requested that the applicant provide additional information describing the methods used, and the basis for conclusions, in determining the portion of nonsafety-related inaccessible piping attached to safety-related SSCs, to be included within the scope of license renewal.In its response to the RAI, dated September 8, 2008, the applicant stated that it had performed a detailed review of the plant physical drawings and had identified the portion of the nonsafety-related piping systems, attached to safety-related SSCs, to be included within the scope of license renewal.Based on its review, the staff finds the applicant's response to RAI 2.1.5.2-2 acceptable because the applicant had reviewed the implementation of its methodology used to identify portions of nonsafety-related SSCs attached to safety-related SSCs to be included within the scope of license renewal and had identified and included the required portions of the nonsafety-related SSCs. The staffs concern described in RAI 2.1.5.2-2 is resolved.Nonsafety-Related SSCs with the Potential for Spatial Interaction with Safety-Related SSCs. The applicant considered physical impacts (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 to identify the portions of nonsafety-related systems with the potential for spatial interaction with safety-related SSCs. The staff notes that the spaces approach focuses on the interaction between nonsafety-related and safety-related SSCs located in the same space, which is defined for the purposes of this review as a structure containing active or passive safety-related SSCs.Physical Impact or Flooding. The applicant identified the nonsafety-related SSCs by performing a review of engineering drawings and the UFSAR. The applicant's review of earthquake experience identified no occurrence of welded steel pipe segments falling due to a strong motion earthquake. Using the guidance in NEI 95-10, the applicant concluded that as long as the effects of aging on supports for piping systems are managed, collapse of piping systems is not credible (except due to flow-accelerated corrosion as considered in the high energy line break (HELB) analysis for high energy systems), and the piping sections are not required to be included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2) due to a physical impact hazard. The applicant determined that high-energy lines are included in scope under 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(2), depending upon their safety classification and location. The applicant's review of industry experience showed that physical impacts can occur due to high-energy piping failures caused by flow-accelerated corrosion. The applicant also determined that nonsafety-related high-energy piping with a potential for spatial interaction with vulnerable safety-related equipment that is not protected from the effects of a HELB failure were included within scope under 10 CFR54.4(a)(2). The applicant evaluated the missiles that could be generated from internal or external events. The nonsafety-related design features that protect safety-related SSCs from such missiles 2-12 Based on its review, the staff finds the applicant's response to RAI 2.1.5.2-1 acceptable because the applicant had reviewed the implementation of its methodology used to identify portions of abandoned, nonsafety-related SSCs attached to safety-related SSCs to be included within the scope of license renewal and had identified and included the required portions of the related SSCs. The staff's concern described in RAI 2.1.5.2-1 is resolved. During the audit, the staff noted the applicant had not clearly defined scoping endpoints for three attached piping segments in the make-up and purification system (license renewal drawing: LR-302-661, Revision 0 for piping connected to valves MU-V111, MU-V27, and MU-V41) because the piping was inaccessible at power. In RAI 2.1.5.2-2, the staff requested that the applicant provide additional information describing the methods used, and the basis for conclusions, in determining the portion of nonsafety-related inaccessible piping attached to safety-related SSCs, to be included within the scope of license renewal. In its response to the RAI, dated September 8,2008, the applicant stated that it had performed a detailed review of the plant physical drawings and had identified the portion of the . nonsafety-related piping systems, attached to safety-related SSCs, to be included within the scope of license renewal. Based on its review, the staff finds the applicant's response to RAI 2.1.5.2-2 acceptable because the applicant had reviewed the implementation of its methodology used to identify portions pf nonsafety-related SSCs attached to safety-related SSCs to be included within the scope of license renewal and had identified and included the required portions of the nonsafety-related SSCs. The staff's concern described in RAI 2.1.5.2-2 is resolved. Nonsafety-Related SSCs with the Potential for Spatial Interaction with Safety-Related SSCs. The applicant considered physical impacts (pipe whip, jet impingement), harsh environments, fl90ding, spray, and leakage when* evaluating the potential for spatial interactions between nonsafety-related systems and safety-related SSCs. The applicant used a spaces approach to identify the portions of nonsafety-related systems with the potential for spatial interaction with safety-related SSCs. The*staff notes that the spaces approach focuses on the interaction between nonsafety-relatedand safety-related SSCs located in the same space, which is defined for the purposes of this review as a structure containing active or passive safety-related ssCs. PhYSical Impact or Flooding. The applicant identified the nonsafety-related SSCs by performing a review of engineering drawings and the UFSAR. The applicant's review of earthquake experience identified no occurrence of welded steel pipe segments falling due to a strong motion earthquake. Using the guidance in NEI 95-10, the applicant concluded that as long as the effects of aging on supports for piping systems are managed, collapse of piping systems is not credible (except due to flow-accelerated corrosion as considered in the high energy line break (HELB) analysis for high energy systems), and the piping sections are not required to be included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2) due toa physical impact hazard. The applicant determined that high-energy lines are included in scope under 10 CFR 54.4( a)( 1) or 10 CFR 54.4(a)(2), depending upon their safety classification and location. The applicant's review of industry experience showed that physical impacts can occur due to high-energy piping failures caused by flow-accelerated corrosion. The applicant also determined that nonsafety-related high-energy piping with a potential for spatial interaction with vulnerable safety-related equipment that is not protected from the effects of a HELB failure were included within scope under 10 CFR 54.4(a)(2). The applicant evaluated the missiles that could be generated from internal or external events. The nonsafety-related design features that protect safety-related SSCs from such rhissiles 2-12 were included within the scope of license renewal. The applicant considered nonsafety-related flood protection features such as walls, dikes, curbs, and seals for inclusion within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). Flood protection features were evaluated with the structures in which they are located as a commodity. Pipe Whip, Jet Impingement, and Harsh Environment. The applicant evaluated the nonsafety-related portions of high energy lines pursuant to 10 CFR 54.4(a)(2). The applicant based its evaluation on a review of documents including the UFSAR, design basis documents, and plant-specific 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. Spray and Leakage. The applicant evaluated moderate and low energy systems that have the potential for spatial interactions due to spray or leakage. Nonsafety-related moderate and low-energy 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 identified corresponding structures for potential spatial interaction based on a review of the CLB and plant walkdowns. Nonsafety-related systems and components that contain water, oil, or steam, and are located inside structures that contain safety-related SSCs, were included within the scope of license renewal, unless they were in an excluded room. Based on plant and industry operating experience, the applicant excluded the nonsafety-related SSCs containing air or gas from the scope of license renewal, with the exception of portions that are attached to safety-related SSCs and required for structural support. Those nonsafety-related SSCs determined to contain fluid, and located within a space containing safety-related SSCs, were included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). Protective Features. The applicant evaluated protective features such as whip restraints, spray shields, supports, and missile and flood barriers installed to protect safety-related SSCs against spatial interaction with nonsafety-related SSCs due to fluid leakage, spray, or flooding. Protective features credited in the plant design, and all equipment supports in safety-related areas, were included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). During the audit, the staff performed a walk-down of the turbine building and determined that a portion of the turbine building contained fluid-filled, nonsafety-related systems which were not included within the scope of license renewal (referred to by the applicant as an "excluded area").The staff noted that since the turbine building is generally an open space, the excluded area was effectively located in the same room as safety-related containment isolation valves (CA-V-5A and CA-V-5B) and that the nonsafety-related, fluid filled'SSCs were not located in an excluded room as described in LRA Section 2.1.5.2. In RAI 2.1.5.2-3, the staff requested that the applicant provide additional information regarding the applicant's rationale for excluding nonsafety-related, fluid-filled SSCs from the scope of license renewal when the SSCs are located in the same room as safety-related SSCs.In its response to the RAI dated September 8, 2008, the applicant stated that it had determined that the scoping of nonsafety-related secondary services system components in the turbine building should have been identified as an exception to the spaces methodology used todetermine nonsafety-related SSCs which could impact safety-related SSCs through spatial interaction, as discussed in the LRA. The applicant also stated that because of the configuration 2-13 were included within the scope of license renewal. The applicant considered nonsafety-related flood protection features such as walls, dikes, curbs, and seals for inclusion within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). Flood protection features were evaluated with the structures in which they are located as a commodity. Pipe Whip. Jet Impingement. and Harsh Environment. The applicant evaluated the nonsafety-related portions of high energy lines pursuant to 10 CFR 54.4(a)(2). The applicant based its evaluation on a review of documents including the UFSAR, design basis documents, and plant-specific 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. Spray and Leakage. The applicant evaluated moderate and low energy systems that have the potential for spatial interactions due to spray or leakage. Nonsafety-related moderate and low-energy 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 identified corresponding structures for potential spatial interaction based on a review of the CLB and plant walkdowns. Nonsafety-related systems and components that contain water, oil, or steam, and are located inside structures that contain safety-related SSCs, were included within the scope of license renewal, unless they were in an excluded room. Based on plant and industry operating experience, the applicant excluded the nonsafety-related SSCs containing air or gas from the scope of license renewal, with the exception of portions that are attached to safety-related SSCs and required for structural support. Those nonsafety-related SSCs determined to contain fluid, and located within a space containing safety-related SSCs, were included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). Protective Features. The applicant evaluated protective features such as whip restraints, spray shields, supports, and missile and flood barriers installed to protect safety-related SSCs against spatial interaction with nonsafety-related SSCs due to fluid leakage, spray, or flooding. Protective features _credited in the plant design, and all equipment supports in safety-related areas, were included within the scope of license renewal in accordance with 10 CFR 54.4(a){2). During the audit, the staff performed a walk-down of the turbine building and determined that a portion of the turbine building contained fluid-filled, nonsafety-related systems which were not included within the scope of license renewal (referred to by the applicant as an "excluded area"). The staff noted that since the turbine building is generally an open space, the excluded area was effectively located in the same room as safety-related containment isolation valves (CA-V-5A and CA-V-5B) and that the nonsafety-related, fluid filledSSCs were not located in an excluded room as described in LRA Section 2.1.5.2. In RAI 2.1.5.2-3, the staff requested that the applicant provide additional information regarding the applicant's rationale for excluding nonsafety-related, fluid-filled SSCs from the scope of license renewal when the SSCs are located in the same room as safety-related SSCs. In its response to the RAI dated September 8, 2008, the applicant stated that it had determined that the scoping of nonsafety-related secondary services system components in the turbine building should have been identified as an exception to the spaces methodology used to determine nonsafety-related SSCs which could impact safety-related SSCs through spatial interaction, as discussed in the LRA. The applicant also stated that because of the configuration 2-13 of the nonsafety-related secondary services system components, and the relationship of this area of the turbine building to the adjacent areas containing safety-related SSCs, the secondary service system components were determined to not have the potential for spatial interaction with safety-related SSCs.Based on its review, the staff finds the applicant's response to RAI 2.1.5.2-3 acceptable because the applicant had reviewed the physical relationship between the secondary service components and the safety-related SSCs and determined that there was no potential for spatial interaction between the nonsafety-related SSCs and the safety-related SSCs, and because the applicant had taken exception to the spaces approach discussed in the LRA. In addition, during the scoping and screening methodology audit, the staff performed a walk down of the turbine building, identified the secondary service components and the nearest safety-related SSCs, and determined that although they were technically located in the same space, as defined in the LRA, there were substantial barriers separating the two sets of SSCs. The staff determined that the substantial barriers provided a basis for the applicant's exception to the spaces approach discussed in the LRA, in this particular application. The staffs concern described in RAI 2.1.5.2-3 is resolved.2.1.4.2.3 Conclusion On the basis of its review of the applicant's scoping process and systems (on a sampling basis), discussions with the applicant, and review of the information provided in the responses to the RAIs, the staff concludes that the applicant's 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 of 10 CFR 54.4(a)(2), and, therefore, is acceptable. 2.1.4.3 Application of the Scoping Criteria in 10 CFR 54.4(a)(3) 2.1.4.3.1 Summary of Technical Information in the Application LRA Section 2.1.3.4, "Systems and Structures Credited for Regulated Events," describes the methodology for identifying those systems and structures within the scope of license renewal in accordance with the Commission's criteria for five regulated events: (1) 10 CFR 50.48, "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 2.1.3.4, "Systems and Structures Credited for Regulated Events," subsection "Fire Protection," describes scoping of systems and structures relied on in safety analyses or plant evaluations to perform functions that demonstrate compliance with the fire protection criterion. The LRA states that all SSCs relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance 10 CFR 50.48 were included in the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(3). Additionally, the LRA states that fire protection SSCs necessary to minimize the effects of a fire and prevent radioactive material from being released to the environment are included in the scope of license renewal in accordance with NUREG-0800, "Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," Section 9.5.1, Appendix C, Revision 5 [sic] and NUREG-1801,"Generic Aging Lessons Learned (GALL) Report," Revision 1.2-14 of the nonsafety-related secondary services system components, and the relationship of this area of the turbine building to the adjacent areas containing safety-related SSCs, the secondary . service system components were determined to not have the potential for spatial interaction with safety-related SSCs. I Based on its review, the staff finds the applicant's response to RAI 2.1.5.2-3 acceptable because the applicant had reviewed the physical relationship between the secondary service components and the safety-related SSCs and determined that there was no potential for spatial interaction between the nonsafety-related SSCs and the safety-related SSCs, and because the had taken exception to the spaces approach discussed in the LRA. In addition, during the scoping and screening methodology audit, the staff performed a walk down of the turbine building, identified the secondary service components and the nearest safety-related SSCs, and determined that although they were technically located in the same space, as defined in the LRA, there were SUbstantial barriers separating the two sets of SSCs. The staff determined that the substantial barriers provided a basis for the applicant's exception to the spaces approach discussed in ,the LRA, in this particular application. The staff's concern described in RAI is resolved. 2.1.4.2.3 Conclusion On the basis of its review of the applicant's scoping process and systems (on a sampling basis), discussions with the applicant, and review of the information provided in the responses to the RAls, the staff concludes that the applicant's 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 of 10 CFR 54.4(a)(2), and, therefore, is acceptable. 2.1.4.3 Application of the Scoping Criteria in 10 CFR 54.4(a)(3) 2.1.4.3.1 Summary of Technical Information in the Application LRA Section 2.1.3.4, "Systems and Structures Credited for Regulated Events," describes the methodology for identifying those systems and structures within the scope of license renewal in . accordance with the Commission's criteria for five regulated events: (1) 10 CFR 50.48, "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, 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 2.1.3.4, "Systems and Structures Credited for Regulated Events," subsection "Fire Protection," describes scoping of systems and structures relied on in safety analyses or plant evaluations to perform functions that demonstrate compliance with the fire protection criterion. The LRA states that all SSCs relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance 10 CFR 50.48 were included in the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(3). Additionally, the LRA states that fire protection SSCs necessary to minimize the effects of a fire and prevent radioactive material from being released to the environment are included in the scope of license renewal in accordance with NUREG-0800, "Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," Section 9.5.1, Appendix C, Revision 5 [sic] and NUREG-1801, "Generic Aging Lessons Learned (GALL) Report," Revision 1. . 2-14 Environmental Qualification. LRA Section 2.1.3.4, "Systems and Structures Credited for Regulated Events," subsection "Environmental Qualification (EQ)," describes the scoping of systems and structures relied on in safety analyses or plant evaluations to perform a function in compliance with the EQ criterion. The LRA states that equipment was determined to be within the scope of license renewal in accordance with 10 CFR 50.49(b)(1), 10 CFR 50.49(b)(2), and 10 CFR 50.49(b)(3), including safety-related electrical equipment; nonsafety-related electrical equipment, whose failure under postulated environmental conditions could prevent compliance with safety functions of the safety-related equipment; and certain post-accident monitoring equipment. A list of these SSCs is included in the EQ basis document, and they are in scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(3). Pressurized Thermal Shock. LRA Section 2.1.3.4, "Systems and Structures Credited for Regulated Events," subsection "Pressurized Thermal Shock (PTS)," describes the scoping of systems and structures relied on in safety analyses or plant evaluations to perform a function in compliance with the PTS criterion. The LRA states that the TMI-1 reactor vessel meets the requirements of 10 CFR 50.61 through the end of its current 40-year license period. Fluence projections were completed to meet a 60-year license period. Components that are projected to meet the definition of beltline material after 60 years of neutron exposure were identified. The PTS onsite basis document summarizes the results of a PTS review of the CLB, and lists the systems containing components credited in PTS evaluations. These systems are included in the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(3). Anticipated Transient Without Scram. LRA Section 2.1.3.4, "Systems and Structures Credited for Regulated Events," subsection "Anticipate Transients Without Scram (ATWS)," describes the scoping of systems and structures relied on in safety analyses or plant evaluations to perform a function in compliance with the ATWS criterion. The LRA states that the diverse scram system needed to mitigate the consequences of an ATWS event are met through a combination of the ATWS mitigation system actuation circuitry (AMSAC), the diverse scram system (DSS), the main turbine trip from feedwater pump trip (TTFWPT), and the heat sink protection system (HSPS).The ATWS onsite basis document lists systems required by 10 CFR 50.62 and structures that are credited with providing physical support and protection for the ATWS systems. The systems and structures are in the scope of license renewal in accordance with the requirements of 10 CFR 50.62 and 10 CFR 54.4(a)(3). Station Blackout. LRA Section 2.1.3.4, "Systems and Structures Credited for Regulated Events," subsection "Station Blackout (SBO)," describes scoping of systems and structures relied on in safety analyses or plant evaluations to perform functions in compliance with the SBO criterion. The LRA states that TMI-1 implemented plant modifications and procedures in response to 10 CFR 50.63 to enable the station to withstand and recover from a SBO of a specified duration and that compliance with 10 CFR 50.63 is documented in UFSAR Section 8.5, staff SERs, and other correspondence related to the SBO rule. The LRA states that the applicant incorporated into its scoping methodology SRP-LR and GALL Report guidance on scoping of equipment relied on to meet the requirements of 10 CFR 50.63 and concluded that SSC that are required to recover from a SBO event are in scope of license renewal. The SBO basis document summarizes the results of a SBO review of the CLB, and lists the SSCs identified as being in the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(3) which include: the switchyard bus and connections, transmission conductors and connections, high voltage insulators, disconnect switches, circuit breakers, substation structures and supports, transformers and auxiliaries, and metal enclosed bus.2-15 Environmental Qualification. LRA Section 2.1.3.4, "Systems and Structures Credited for Regulated Events," subsection "Environmental Qualification (EO)," describes the scoping of systems and structures relied on in safety analyses or plant evaluations to perform a function in compliance with the EO criterion. The LRA states that equipment was determined to be within the scope of license renewal in accordance with 10 CFR 50.49(b)(1), 10 CFR 50.49(b)(2), and 10 CFR 50.49(b)(3), including safety-related electrical equipment; nonsafety-related electrical equipment, whose failure under postulated environmental conditions could prevent compliance with safety functions of the safety-related equipment; and certain post-accident monitoring equipment. A list of these SSCs is included in the EO basis document, and they are in scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(3). Pressurized Thermal Shock. LRA Section 2.1.3.4, "Systems and Structures Credited for Regulated Events," subsection "Pressurized Thermal Shock (PTS)," describes the scoping of systems and structures relied on in safety analyses or plant evaluations to perform a function in compliance with the PTS criterion. The LRA states that the TMI-1 reactor vessel meets the requirements of 10 CFR 50.61 through the end of its current 40-year license period. Fluence projections were completed to meet a 60-year license period. Components that are projected to meet the definition of beltline material after 60 years of neutron exposure were identified. The PTS onsite basis document summarizes the results of a PTS review of the CLB, and lists the systems containing components credited in PTS evaluations. These systems are included in the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(3). Anticipated Transient Without Scram. LRA Section 2.1.3.4, "Systems and Structures Credited for Regulated Events," subsection "Anticipate Transients Without Scram (ATWS)," describes the scoping of systems and structures relied on in safety analyses or plant evaluations to perform a function in compliance with the ATWS criterion. The LRA states that the diverse scram system needed to mitigate the consequences of an ATWS event are met through a combination of the A TWS mitigation system actuation circuitry (AMSAC), the diverse scram system (DSS), the main turbine trip from feedwater pump trip (TTFWPT), and the heat sink protection system (HSPS) . . The A TWS onsite basis document lists systems required by 10 CFR 50.62 and structures that are credited with providing physical support and protection for the A TWS systems. The systems and structures are in the scope of license renewal in accordance with the requirements of 10 CFR 50.62 and 10 CFR 54.4(a)(3). Station Blackout. LRA Section 2.1.3.4, "Systems and Structures Credited for Regulated Events," subsection "Station Blackout (SBO)," describes scoping of systems and structures relied on in safety analyses or plant evaluations to perform functions in compliance with the SBO criterion. The LRA states that TMI-1 implemented plant modifications and procedures in response to 10 CFR 50.63 to enable the station to withstand and recover from a SSO of a specified duration and that compliance with 10 CFR 50.63 is documented in UFSAR Section 8.5, staff SERs, and other correspondence related to the SBO rule. The LRA states that the applicant incorporated into its scoping methodology SRP-LR and GALL Report guidance on scoping of equipment relied on to meet the requirements of 10 CFR 50.63 and concluded that SSC that are required to recover from a SSO event are in scope of license renewal. The SSO basis document summarizes the results of a SBO review of the CLB, and lists the SSCs identified as being in the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(3) which include: the switchyard bus and connections, transmission conductors and connections, high voltage insulators, disconnect switches, circuit breakers, substation structures and supports, transformers and auxiliaries, and metal enclosed bus. 2-15 2.1.4.3.2 Staff Evaluation The staff reviewed the applicant's approach to identifying mechanical systems and structures relied upon to perform functions meeting the requirements of the fire protection, EQ, PTS, ATWS, and SBO regulations. As part of this review, the staff discussed the methodology with the applicant, reviewed the documentation developed to support the approach, and evaluated a sample of the mechanical systems and structures indicated as within the scope of license renewal pursuant to 10 CFR 54.4(a)(3).The applicant's implementing procedures describe the process for identifying systems and structures within the scope of license renewal. The procedures state that all mechanical SSC that perform functions addressed in 10 CFR 54.4(a)(3) are to be included within the scope of licenserenewal and that the results are to be documented in scoping results reports. The results reports reference the information in sources for determining the SSCs credited for compliance with the events listed in the specified regulations. Fire Protection. LRA Section 2.1.3.4 describes the SSCs 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 those required to demonstrate post-fire safe shutdown capabilities, those required for fire detection and suppression and those required to meet commitments made to Appendix A to Branch Technical Position on Auxiliary Power Conversion System BTP-APCSB 9.5-1, "Guidelines for Fire Protection for Nuclear Power Plants Docketed Prior to July 1, 1976." The applicant stated that those SSCs credited with fire prevention, detection, and mitigation in areas containing equipment important to the plant's safe operation and equipment credited to achieve safe shutdown in the event of a fire are within the scope of license renewal. The applicant's basis documents indicated that it had included systems and structures in the scope of license renewal required for post-fire safe shutdown, fire detection suppression, and commitments made to Appendix A to BTP-APCSB 9.5-1.The applicant considered CLB documents to identify systems and structures within the scope of license renewal. These documents include the UFSAR, system flow diagrams, fire hazards analysis report, system design description for remote shutdown, piping drawings, operating procedures, and system design basis documents. The staff reviewed the scoping results in l conjunction with the LRA and CLB information to validate the methodology for including the systems and structures within the scope of license renewal. The staff finds that the scoping results include systems and structures that perform intended functions to meet the requirements of 10 CFR 50.48. The staff determined that the applicant's scoping methodology was adequate for including SSCs credited with performing fire protection functions within the scope of license renewal.Environmental Qualification. The applicant used the CRL to search and identify the EQ items.The CRL includes component data with an EQ data field. The staff reviewed the LRA, implementing procedures, and scoping results to verify that the applicant had identified SSCs within the scope of license renewal. The staff determined that the applicant's scoping methodology was adequate for identifying EQ SSCs within the scope of license renewal.Pressurized Thermal Shock. The applicant included the steel reactor vessel beltline shell, including plates, forgings, and welds, within the scope of license renewal in accordance with 10 CFR 54.4(a)(3) criteria. These components were analyzed, and fluence projections were completed to demonstrate compliance with 10 CFR 50.61. The staff reviewed the scoping basis 2-16 2.1.4.3.2 Staff Evaluation The staff reviewed the applicant's approach to identifying mechanical systems and structures relied upon to perform functions meeting the requirements of the fire protection, EO, PTS, A TWS, and SBO regulations. As part of this review, the staff discussed the methodology with the applicant, reviewed the documentation developed to support the approach, and evaluated a sample of the mechanical systems and structures indicated as within the scope of license renewal pursuant to 10 CFR 54.4(a)(3). ' The applicant's implementing procedures describe the process for identifying systems and structures within the scope of license renewal. The procedures state that all mechanical SSC that perform functions addressed in 10 CFR 54.4(a)(3) are to be included within the scope of license renewal and that the results are to be documented in scoping results reports. The results reports reference the information in sources for determining the SSCs credited for compliance withithe events listed in the specified regulations. !, Fire Protection. LRA Section 2.1.3.4 describes the SSCs 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 those required to demonstrate post-fire safe shutdown capabilities, those required for fire detection and suppression and those required to meet commitments made to Appendix A to Branch Technical Position on Auxiliary Power Conversion System BTP-APCSB 9.5-1, "Guidelines for Fire Protection for Nuclear Power Plants Docketed Prior to July 1, 1976." The applicant stated that those SSCs credited with fire prevention, detection, and mitigation in areas containing equipment important to the plant's safe operation and equipment credited to.achieve safe shutdown inthe event of a fire are within the scope of license renewal. The applicant's basis documents indicated that it had included systems and structures in the scope of license renewal required for safe shutdown, fire detection suppression, and commitments made to Appendix A to 9.5-1. The applicant considered CLB documents to identify systems and structures within the scope of license renewal. These documents include the UFSAR, system flow diagrams, fire hazards analysis report, system design description for remote shutdown, piping drawings, operating procedures, and system design basis documents. The staff reviewed the scoping results in:1 conjunction with the LRA and CLB information to validate the methodology for including the systems and structures within the scope of license renewal. The staff finds that the scoping results include systems and structures that perform intended functions to meet the requirements of 10 CFR 50.48. The staff determined that the applicant's scoping methodology was adequate for including SSCs credited with performing fire protection functions within the scope of license renewal. I' Environmental Qualification. The applicant used the CRL to search and identify the EQ items. The CRL includes component data with an EQ data field. The staff reviewed the LRA, implementing procedures, and scoping results to verify that the applicant had identified SSCs within the scope of license renewal. The staff determined that the applicant's scoping methodology was adequate for identifying EO SSCs within the scope of license renewal. Pressurized Thermal Shock. The applicant included the steel reactor vessel beltline shell, including plates, forgings, and welds, within the scope of license renewal in accordance with 10 CFR 54.4(a)(3) criteria. These components were analyzed, and fluence projections were completed to demonstrate compliance with 10 CFR 50.61. The staff reviewed the scoping basis 2-16 document to verify the systems and components needed to demonstrate compliance with the requirements of 10 CFR 50.61. Additionally, the staff reviewed the scoping basis documents and determined that the methodology was appropriate for identifying SSCs with functions credited for complying with the PTS regulation and within the scope of license renewal. The staff finds that the scoping results, which included the steel reactor vessel beltline shell, include systems and structures that perform intended functions to meet the requirements of 10 CFR 50.61. The staffdetermined that the applicant's scoping methodology was adequate for including SSCs credited in meeting PTS requirements within the scope of license renewal.Anticipated Transient Without Scram. The applicant generated a list of TMI-1 plant systems credited for ATWS mitigation based on its review of the CRL, UFSAR, Technical Specifications, and NRC correspondence, including NRC Letter C311-89-3001, "NRC Review of ATWS Implementation," 10 CFR 50.62 safety evaluations, and approved system design descriptions. The staff reviewed these documents and the LRA, in conjunction with the scoping results, to validate the methodology for identifying ATWS systems and structures that are within the scope of license renewal. The staff found that the scoping results included systems and structures that perform intended functions meeting 10 CFR 50.62 requirements. The staff determined that theapplicant's scoping methodology was adequate for identifying SSCs with functions credited for complying with the ATWS regulation. Station Blackout. The applicant followed a two-step process to identify SSCs credited with performing intended functions to comply with the SBO requirement. The first step identified those systems and structures associated with coping and safe shutdown of the plant following an SBO event. The second step identified those systems and structures that are required to restore the plant following the SBO event. In order to identify SBO systems and structures involved in shutdown and restoration, the applicant reviewed its restoration procedures, its SBO evaluation report, relevant mechanical and electrical diagrams, and UFSAR Sections 8.2 (Electrical System Design) and 8.5 (SBO evaluation). The staff reviewed these documents and the LRA in conjunction with the scoping results to validate the applicant's methodology. The staff finds that the scoping results included systems and structures that perform intended functions to meet the requirements of 10 CFR 50.63. The staff determined that the applicant's scoping methodology was adequate for identifying SSCs with functions credited in complying with the SBO regulations. 2.1.4.3.3 Conclusion On the basis of the sample reviews, discussions with the applicant, review of the LRA, and review of the applicant's scoping process, the staff concludes that the applicant's methodology for identifying systems and structures meets the scoping criteria of 10 CFR 54.4(a)(3), and, therefore, is acceptable. 2.1.4.4 Plant-Level Scoping of Systems and Structures 2.1.4.4.1 Summary of Technical Information in the Application System and Structure-Level Scopinq. The applicant documented its methodology for performing the scoping of systems and structures in accordance with the requirements of 10 CFR 54.4(a) in the LRA, guidance documents, and scoping and screening reports. The applicant's approach to system and structure-level scoping provided in the site guidance documents and implementing procedures is consistent with the methodology described in LRA Section 2.1. Specifically, the procedures specify that the personnel performing license renewal scoping use CLB documents and describe the system or structure, and include a list of functions that the system or structure is 2-17* document to verify the systems and components needed to demonstrate compliance with the requirements of 10 CFR 50.61. Additionally, the staff reviewed the scoping basis documents and determined that the methodology was appropriate for identifying SSCs with functions credited for complying with the PTS regulation and within the scope of license renewal. The staff finds that the scoping results, which included the steel reactor vessel beltline shell, include systems and structures that perform intended functions to meet the requirements of 10 CFR 50.61. The staff determined that the applicant's scoping methodology was adequate for including SSCs credited in meeting PTS requirements within the scope of license renewal. AntiCipated Transient Without Scram. The applicant generated a list of TMI-1 plant systems credited for ATWS mitigation based on its revieW of the CRL, UFSAR, Technical Specifications, and NRC correspondence, including NRC Letter C311-89-3001, "NRC Review of A TWS . Implementation," 10 CFR 50.62 safety evaluations, and approved system design descriptions. The staff reviewed these documents and the LRA, in conjunction with the scoping results, to validate the methodology for identifying A TWS systems and structures that are within the scope of license renewal. The staff found that the scoping results included systems and structures that perform intended functions meeting 10 CFR 50.62 requirements. The staff determined that the applicant's scoping methodology was adequate for identifying SSCs with functions credited for complying with the ATWS regulation. Station Blackout. The applicant followed a two-step process to identify SSCs credited with performing intended functions to comply with the SBO requirement. The first step identified those systems and structures associated with coping and safe shutdown of the plant following an SBO event. The second step identified those systems and structures that are required to restore the plantfollowing the SBO event. In order to identify SBO systems and structures involved in shutdown and restoration, the applicant reviewed its restoration procedures, its SBO evaluation report, relevant mechanical and electrical diagrams, and UFSAR Sections 8.2 (Electrical System Design) and 8.5 (SBO evaluation). The staff reviewed these documents and the LRA in conjunction with the scoping results to validate the applicant's methodology. The staff finds that the scoping results included systems and structures that perform intended functions to meet the requirements of 10 CFR 50.63. The staff determined that the applicant's scoping methodology was adequate for identifyingSSCs with functions credited in complying with the SBO regulations. 2.1.4.3.3 Conclusion On the basis of the sample reviews, discussions with the applicant, review of the. LRA, and review of the applicant's scoping process, the staff concludes that the applicant's methodology for identifying systems and structures meets the scoping criteria of 10 CFR 54.4(a)(3), and, therefore, is acceptable. 2.1.4.4 Plant-Level Scoping of Systems and Structures 2.1.4.4.1 Summary of Technical Information in the Application System and Structure-Level Scoping. The applicant documented its methodology for performing the scoping of systems and structures in accordance with the requirements of 10 CFR 54.4(a) in the LRA,guidance documents, and scoping and screening reports. The applicant's approach to system and structure-level scoping provided in the site guidance documents and implementing procedures is consistent with the methodology described in LRA Section 2.1. Specifically, the procedures specify that the personnel performing license renewal scoping use CLB documents and describe the system or structure, and include a list of functions that the system or structure is 2-17 required to accomplish. Sources of information include the UFSAR, preliminary safety analysis report, fire hazards analysis report, EQ master list, design basis documents, maintenance rule information, controlled plant component database, plant drawings, and docketed correspondence. The applicant then compared identified systems or structures function lists to the scoping criteria to determine whether the functions met the scoping criteria of 10 CFR 54.4(a).If any part of a system or structure met any of the license renewal scoping criteria, the system or structure was included in the scope of license renewal. The system and structure scoping results included an overall system/structure description, an evaluation of each of the 10 CFR 54.4(a)scoping criteria, and the basis for the conclusion reached. The applicant developed evaluation boundaries to document the system and structure-level scoping determinations, and to define the in-scope SSCs to support the subsequent screening and AMR processes. The boundaries for the in-scope systems and structures were defined and documented in a manner for each discipline that assured the in-scope SSCs were included in the screening process.Component Level Scoping. After the applicant identified the intended functions of systems or structures within the scope of license renewal, a review was performed to determine which components and structures support the system's license renewal intended functions. The i components that support intended functions were considered within the scope of license renewal and screened to determine if an AMR was required. The applicant considered three groups of SCs while performing component level scoping: (1) mechanical, (2) structural, and (3) electrical. Commodity Groups Scopinq. The applicant applied commodity group scoping to structural and electrical SCs as discussed in LRA Sections 2.4.13, 2.4.17, and 2.5.2.Insulation. LRA Section 2.4.13, "Structural Commodities," states that designated insulation insidethe reactor building is safety-related and is required to resist seismic loading conditions and is in scope for license renewal. The applicant further stated that nonsafety-related piping and component insulation is included within the scope of license renewal when it is located inside structures within the scope of license renewal, or if it performs a function for freeze protection of heat traced piping and components. The applicant further stated that anti-sweat piping andl component insulation, and thermal piping and component insulation inside structures that are not in the scope of license renewal, are not included in the scope of license renewal.Consumables. LRA Section 2.1.6.4, "Consumables," describes the consumables to be included within the scope of license renewal. The staff noted that the information in Table 2.1-3 of the SRP-LR was used to categorize and evaluate consumables. The applicant divided consumlables into the following four categories for the purpose of license renewal: (a) packing, gaskets, seals, and O-rings; (b) structural sealants; (c) oil, grease, and component filters; and (d) system filters, fire extinguishers, fire hoses, and air packs. A discussion of each category follows: (a) The staff notes that packing, gaskets, seals, and O-rings are typically used to provide a leakproof seal when components are mechanically joined together and that these items are commonly found in components such as valves, pumps, heat exchangers, ventilationsunits or ducts, and piping segments. The applicant stated that based on ANSI B31.1 and the ASME B&PV Code Section III, the subcomponents of pressure-retaining components are not pressure-retaining parts, and therefore, these subcomponents are not relied on to perform a pressure boundary intended function and are not subject to an AMR.2-18 required to accomplish. Sources of information include the UFSAR, preliminary safety analysis report, fire hazards analysis report, EQ master list, design basis documents, maintenance rule information, controlled plant component database, plant drawings, and docketed correspondence. The applicant then compared identified systems or structures function lists to the scoping criteria to determine whether the functions met the scoping criteria of 10 CFR 54.4(a). If any part of a system or structure met any of the license renewal scoping criteria, the or structure was included in the scope of license renewal. The system and structure scoping results included an overall system/structure description, an evaluation of each of the 10 CFR 54.4(a) scoping criteria, and the basis for the conclusion reached. The applicant developed evaluation boundaries to document the system and structure-level scoping determinations, and to define the in-scope SSCs to support the subsequent screening and AMR processes. The boundaries for the in-scope systems and structures were defined and documented in a manner for each discipline that assured the in-scope SSCs were included in the screening process. Component Level Scoping. After the applicant identified the intended functions of systems or structures within the scope of license renewal, a review was performed to determine which components and structures support the system's license renewal intended functions. The i! components that support intended functions were considered within the scope of license renewal and screened to determine if an AMR was required. The applicant considered three groups' of SCs while performing component level scoping: (1) mechanical, (2) structural, and (3) electrical. Commodity Groups Scoping. The applicant applied commodity group scoping to structural and electrical SCs as discussed in LRA Sections 2.4.13, 2.4.17, and 2.5.2. . Insulation. LRA Section 2.4.13, "Structural Commodities," states that deSignated insulatiorl' inside the reactor building is safety-related and is required to resist seismic loading conditions and is in scope for license renewal. The applicant further stated that nonsafety-related piping and component insulation is included within the scope of license renewal when it is located inside structures within the scope of license renewal, or if it performs a function for freeze protection of heat traced piping and components. The applicant further stated that anti-sweat piping andll component insulation, and thermal piping and component insulation inside structures that are not in the scope of license renewal, are not included in the scope of license renewal. Consumables. LRA Section 2.1.6.4, "Consumables," describes the consumables to be included within the scope of license renewal. The staff noted that the information in Table 2.1-3 of th'e SRP-LR was used to categorize and evaluate consumables. The applicant divided consum,ables into the following four categories for the purpose of license renewal: (a) packing, gaskets, and O-rings; (b) structural sealants; (c) oil, grease, and component filters; and (d) system filters, fire extinguishers, fire hoses, and air packs. A discussion of each category follows: (a) The staff notes that packing, gaskets, seals, and O-rings are typically used to provide a leakproof seal when components are mechanically joined together and that these items are commonly found in components such as valves, pumps, heat exchangers, ventilations units or ducts, and piping segments. The applicant stated that based on ANSI B31.1 and the ASME B&PV Code Section III, the SUbcomponents of pressure-retaining components are not pressure-retaining parts, and therefore, these SUbcomponents are not relied on to perform a pressure boundary intended function and are not subject to an AMR. 2-18 (b) The staff noted that limited situations may exist in which materials are important in maintaining the integrity of the components to which they are connected and that structural sealants are subject to an AMR and are evaluated with the structures that contain them. The applicant stated that AMRs were required for structural sealants in in-scope structures.(c) The applicant stated that oil, grease, and component filters have been treated as consumables because they are short-lived and periodically replaced. The applicant further stated that plant procedures are used for the replacement of oil, grease, and filters in components that are within the scope of license renewal.(d) The applicant stated that system filters are replaced in accordance with plant procedures which are based on vendor manufacturers' requirements and system testing. Theapplicant further stated that fire extinguishers, fire hoses, and air packs are periodically tested, inspected, and replaced based on condition. The applicant stated that periodic inspections are implemented by plant procedures and that system filters, fire extinguishers, fire hoses, and air packs are within the scope of license renewal, but not subject to an AMR.2.1.4.4.2 Staff Evaluation The staff reviewed the applicant's methodology for performing the plant-level scoping of systems and components to ensure it was consistent with 10 CFR 54.4. The methodology used to determine the systems and components within the scope of license renewal was documented in implementing procedures and scoping results reports for mechanical systems. The scoping process defined the plant in terms of systems and structures. Specifically, the implementing procedures identified the systems and structures that are subject to 10 CFR 54.4 review, described the processes for capturing the results of the review, and were used to determine if the system or structure performed intended functions consistent with the criteria of 10 CFR 54.4(a). The process was completed for all systems and structures to ensure that the entire plant was addressed. The applicant documented the results of the plant-level scoping process in accordance with the guidance documents. The results were provided in the systems and structures documents and reports which contained information including a description of the system or structure, a listing of functions performed by the system or structure, identification of intended functions, the 10 CFR 54.4(a) scoping criteria met by the system or structure, references, and the basis for the classification of the system or structure intended functions. During the audit, the staff reviewed a sampling of the documents and reports and determined that the applicant's scoping results contained an appropriate level of detail to document the scoping process.2.1.4.4.3 Conclusion On the basis of its review of the LRA, scoping and screening implementing procedures, and a sampling of system scoping results during the audit, the staff concludes that the applicant's methodology for plant-level scoping appropriately identifies systems, structures, component types, and commodity groups within the scope of license renewal and their intended functions in accordance with the requirements of 10 CFR 54.4 and, therefore is acceptable. 2-19 (b) The staff noted that limited situations may exist in which materials are important in maintaining the integrity of the components to which they are connected and that structural sealants are subject to an AMR and are evaluated with the structures that contain them. The applicant stated that AMRswere required for structural sealants in scope structures. (c) The applicant stated that oil, grease, and component filters have been treated as consumables because they are short-lived and periodically replaced. The applicant further stated that plant procedures are used for the replacement of oil, grease, and filters in components that are within the scope of license renewal. . (d) The applicant stated that system filters are replaced in accordance with plant procedures which are based on vendor manufacturers' requirements and system testing. The applicant further stated that fire extinguishers, fire hoses, and air packs are periodically tested, inspected, and replaced based on condition. The applicant stated that periodic inspections are implemented by plant procedures and that system filters, fire extinguishers, fire hoses, and air packs are within the scope of license renewal, but not subject to an AMR. 2.1.4.4.2 Staff Evaluation The staff reviewed the applicant's methodology for performing the plant-level scoping of systems and components to ensure it was consistent with 10 CFR 54.4. The methodology used to determine the systems and components within the scope of license renewal was documented in implementing procedures and scoping results reports for mechanical systems. The scoping process defined the plant in terms of systems and structures. Specifically, the implementing procedures identified the systems and structures that are subject to 10 CFR 54.4 review, described the processes for capturing the results of the review, and were used to determine if the system or structure performed intended functions consistent with the criteria of 10 CFR 54.4(a). The process was completed for all systems and structures to ensure that the entire plant was addressed. The applicant documented the results of the plant-level scoping process in accordance with the guidance documents. The results were provided in the systems and structures documents and reports which contained information including a description of the system or structure, a listing of functions performed by the system or structure, identification of intended functions, the 10 CFR 54.4(a) scoping criteria met by the system or structure, references, and the basis for the classification of the system or structure intended functions. During the audit, the staff reviewed a sampling of the documents and reports and determined that the applicant's scoping results contained an appropriate level of detail to document the scoping process. 2.1.4.4.3 Conclusion On the basis of its review of the LRA, scoping and screening implementing procedures, and a sampling of system scoping results during the audit, the staff concludes that the applicant's methodology for plant-level scoping appropriately identifies systems, structures, component types, and commodity groups within the scope of license renewal and their intended functions in accordance with the requirements of 10 CFR 54.4 and, therefore is acceptable. 2-19 2.1.4.5 Mechanical Component 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. The staff notes that 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 applicant stated that in-scope boundaries for mechanical systems and structures were developed and are depicted on the license renewal boundary drawings. The mechanical boundary drawings show the mechanical components within the scope of license renewal, , including those components that are only within the scope of license renewal in accordance with 10 CFR 54.4(a)(2), using color-coding. The staff noted that end points for the portions within the scope of license renewal were clearly delineated and that notes were added to the drawings as necessary to clarify the endpoints when they do not occur at a component or feature already depicted on the drawing.The applicant stated that for mechanical systems, the mechanical components that support the system intended functions were included in the scope of license renewal and are depicted on the applicable system flow diagrams. The applicant further stated that mechanical system flow diagrams were used to create license renewal boundary drawings showing the in-scope components. The applicant stated that components that are required to support a safety-related function, or a function that demonstrates compliance with one of the license renewal regulated events, were identified on the system flow diagrams by green highlighting and thatnonsafety-related components that are connected to safety-related components and are required to provide structural support at the safety/nonsafety interface, or components whose failure could prevent satisfactory accomplishment of a safety-related function due to spatial interaction With safety-related SSCs, were identified by red highlighting. The staff conducted a review of component information contained in the CRL and confirmed the scope of components in the system and conducted plant walkdowns as necessary to obtain additional information. 2.1.4.5.2 Staff Evaluation The staff evaluated LRA Section 2.1.5 and the guidance in the applicant's implementing procedures and system and structure scoping report, to perform the review of the mechanical component scoping process. The staff noted that the implementing procedures provide instructions for identifying the evaluation boundaries and that determination of the mechanical system evaluation boundaries required an understanding of system operations in support of intended functions. This process was based on the review of the UFSAR, preliminary safety analysis report, fire hazards analysis report, EQ master list, design basis documents, maintenance rule information, controlled plant component database, plant drawings, and docketed correspondence. The 1'evaluation boundaries for mechanical systems were documented on license renewal boundary drawings that were created by marking mechanical piping and instrumentation diagrams to indicate the components within the scope of license renewal. Components within the evaluation boundary were reviewed to determine whether they perform an intended function. Intended functions were established based on whether a particular function of a component was necessary to support the system functions that meet the scoping criteria.The staff reviewed the implementing procedures and CLB documents associated with mechanical system scoping, and found that the guidance and CLB source information noted above were 2-20 2.1.4.5 Mechanical Component 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. The staff notes that 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 applicant stated that in-scope boundaries for mechanical systems and structures were developed and are depicted on the license renewal boundary drawings. The mechanical boundary drawings show the mechanical components within the scope of license renewal, I including those components that are only within the scope of license renewal in accordance with 10 CFR 54.4(a)(2), using color-coding. The staff noted that end points for the portions within the scope of license renewal were clearly delineated and that notes were added to the drawings as necessary to clarify the endpoints when they do not occur at a component or feature already depicted on the drawing. The applicant stated that for mechanical systems, the mechanical components that support the system intended functions were included in the scope of license renewal and are depicted on the applicable system flClw diagrams. The applicant further stated that mechanical system flow' diagrams were used to create license renewal boundary drawings showing the in-scope components. The applicant stated that components that are required to support a safety-related function, or a function that demonstrates compliance with one of the license renewal regulated events, were identified on the system flow diagrams by green highlighting and that nonsafety-related components that are connected to safety-related components and are required to provide structural support at the safety/nonsafety interface, or components whose failure,! could prevent satisfactory accomplishment of a safety-related function due to spatial interaction with safety-related SSCs, were identified by red highlighting. The staff conducted a review of component information contained in the CRL and confirmed the scope of components in th43 system and conducted plant walkdowns as necessary to obtain additional information. 2.1.4.5.2 Staff Evaluation The staff evaluated LRA Section 2.1.5 and the guidance in the applicant's implementing i procedures and system and structure scoping report, to perform the review of the mechani6al component scoping process. The staff noted that the implementing procedures provide. instructions for identifying the evaluation boundaries and that determination of the mechanical system evaluation boundaries required an understanding of system operations in support of intended functions. This process was based on the review of the UFSAR, preliminary safety analysis report, fire hazards analysis report, EQ master list, design basis documents, maintenance rule information, controlled plant component database, plant drawings, and docketed correspondence. The i' evaluation boundaries for mechanical systems were documented on license renewal boundary drawings that were created by marking mechanical piping and instrumentation diagrams to indicate the components within the scope of license renewal. Components within the evaluation boundary were reviewed to determine whether they perform an intended function. Intended functions were established based on whether a particular function of a component was necessary to support the system functions that meet the scoping criteria. The staff reviewed the implementing procedures and CLB documents associated with mechanical system scoping, and found that the guidance and CLB source information noted above were 2-20 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 theapplicant's- license renewal project management staff and reviewed documentation pertinent to the scoping process. The staff assessed whether the applicant had appropriately applied thescoping methodology outlined in the LRA and implementing procedures and whether the scoping results were consistent with CLB requirements. The staff determined that the applicant's proceduralized methodology was consistent with the description provided in the LRA Section 2.1.5 and the guidance contained in the SRP-LR, Section 2.1, and was adequately implemented. During the scoping and screening methodology audit, the staff discussed the scoping methodology and, on a sampling basis, reviewed the applicant's scoping reports for identifying main steam system and decay heat removal system mechanical component types meeting the scoping criteria as defined in the Rule. The staff also reviewed the scoping methodology implementing procedures and discussed the methodology and results with the applicant. The staff confirmed that the applicant had identified and used pertinent engineering and licensing information to determine the main steam and decay heat removal system mechanical component types required to be within the scope of license renewal. As part of the review process, the staff evaluated each system intended function identified for the main steam and decay heat removal systems, the basis for inclusion of the intended function, and the process used to identify each ofthe system component types. The staff verified that the applicant had identified and highlighted system piping and instrumentation diagrams (P&IDs) to develop the license renewal boundaries in accordance with the procedural guidance. The applicant was knowledgeable about the processand conventions for establishing boundaries as defined in the license renewal implementing procedures. Additionally, the staff confirmed that the applicant had peer reviewed the results in accordance with the governing procedures. Specifically, other license renewal staff knowledgeable about the system had independently reviewed the marked-up drawings to ensure accurate identification of system intended functions. The applicant performed additional cross-discipline verification and independent reviews of the resultant highlighted drawings before final approval of the scoping effort.2.1.4.5.3 Conclusion On the basis of its review of the LRA, scoping implementing procedures, the sample system review, and discussions with the applicant, the staff concludes that the applicant's methodology for mechanical component scoping appropriately identifies mechanical systems within the scope of license renewal is in accordance with the requirements of 10 CFR 54.4, and therefore, is acceptable. 2.1.4.6 Structural Scoping 2.1.4.6.1 Technical Information in the Application In addition to the information previously discussed in Section 2.1.4.4.1, LRA Section 2.1.5.5"Scoping Boundary Determination," subsection "Structures," stated that for the structural scoping effort, the structures were determined to be within the scope of license renewal through a review of applicable plant design drawings of the structure, and confirmed through plant walkdowns. The applicant identified the structures determined to be within the scope of license renewal, and were included in a marked-up onsite site plan boundary layout drawing.2-21 acceptable to identify mechanical components and support structures in mechanical systems that are within the scope of license renewal. The staff conducted detailed discussions with the applicant's*license renewal project management staff 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 were consistent with CLB requirements. The staff determined that the applicant's proceduralized methodology was consistent with the description provided in the LRA Section 2.1.5 and the guidance contained in the SRP-LR, Section 2.1, and was adequately implemented. During the scoping and screening methodology audit, the staff discussed the scoping methodology and, on a sampling basis, reviewed the applicant's scoping reports for identifying main steam system and decay heat removal system mechanical component types meeting the scoping criteria as defined in the Rule. The staff also reviewed the scoping methodology implementing procedures and discussed the methodology and results with the applicant. The staff confirmed that the applicant had identified and used pertinent engineering and licensing information to determine the main steam and decay heat removal system mechanical component types required to be within the scope of license renewal. As part of the review process, the staff evaluated each system intended function identified for the main steam and decay heat removal systems, 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 piping and instrumentation diagrams (P&IDs) to develop the license renewal boundaries in accordance with the procedural guidance. The applicant was knowledgeable about the process and conventions for establishing boundaries as defined in the license renewal implementing procedures. Additionally, the staff confirmed that the applicant had peer reviewed the results in accordance with the governing procedures. Specifically, other license renewal staff knowledgeable about the system had independently reviewed the marked-up drawings to ensure accurate identification of system intended functions. The applicant performed additional cross-discipline verification and independent reviews of the resultant highlighted drawings before final approval of the scoping effort. 2.1.4.5.3 Conclusion . On the basis of its review of the LRA, scoping implementing procedures, the sample system review, arid discussions with the applicant, the staff concludes that the applicant's methodology for mechanical component scoping appropriately identifies mechanical systems within the scope of license renewal is in accordance with the requirements of 10 CFR 54.4, and therefore, is acceptable. 2.1.4.6 Structural Scoping 2.1.4.6.1 Technical Information in the Application In addition to the information previously discussed in Section 2.1.4.4.1, LRA Section 2.1.5.5 "Scoping Boundary Determination," subsection "Structures," stated that for the structural scoping effort, the structures were determined to be within the scope of license renewal through a review of applicable plant design drawings of the structure, and confirmed through plant walkdowns. The applicant identified the structures determined to be within the scope of license renewal, and were included in amarked-up onsite site plan boundary layout drawing. 2-21 2.1.4.6.2 Staff Evaluation The staff reviewed the applicant's approach to the scoping of structures relied upon to perform the functions described in 10 CFR 54.4(a). As part of this review, the staff discussed the methodology with the applicant, reviewed the documentation developed to support the review, and evaluated the scoping results for a sample of structures that were identified within the scope of license renewal. The applicant had identified and developed a list of plant structures and the structures intended functions through a review of UFSAR, CRL, design basis documents (DBDs), plant engineering drawings, plant operating manuals and procedures, plant walkdowns, and docketed correspondence. Each structure the applicant identified was evaluated against the criteria of 10 CFR 54.4(a)(1), (a)(2), and (a)(3).The staff reviewed selected portions of the UFSAR, CRL, database screening form, process flowchart, structural drawings, and implementing procedures to verify the adequacy of the methodology. During the scoping and screening methodology audit, the staff discussed the scoping methodology with the applicant and, on a sampling basis, reviewed the applicant's scoping reports, including information contained in the source documentation, for the turbine building and the intermediate building to verify that application of the methodology would provide the results as documented in the LRA. The staff reviewed the applicant's methodology for identifying structures meeting the scoping criteria as defined in the Rule. The staff verified that the applicant had identified and used pertinent engineering and licensing information in order to determine that the turbine building and the intermediate building are required to be within the scope of license renewal. As part of the review process, the staff evaluated the intended functions identified for the turbine building and the intermediate building and the components, the basis for inclusion of the intended function, and the process used to identify each of the component types.2.1.4.6.3 Conclusion On the basis of its review of information in the LRA, scoping implementing procedures, and a sampling review of structural scoping results, the staff concludes that the applicant's methodology for the scoping of the structures within the scope of license renewal is in accordance with the requirements of 10 CFR 54.4, and therefore, is acceptable. 2.1.4.7 Electrical Component Scoping 2.1.4.7.1 Technical Information in the Application LRA Section 2.1.1, "Introduction," states that the scoping process for electrical and instrumentation and control (I&C) systems was performed in a manner similar to the scoping process that was applied to mechanical systems and structures. Electrical and I&C components within the in-scope mechanical systems and the in-scope electrical and I&C systems were included within the scope of license renewal, regardless of the intended function of the component, which is the result of a "bounding" approach for the review of electrical components. LRA Section 2.1.6.1 states that after the scoping of electrical and I&C components was performed, the in-scope electrical components were categorized into electrical commodity groups.The staff noted that the commodity groups include similar electrical and I&C components with common characteristics and that component level intended functions of the commodity groups were identified. That staff noted that during the screening process, some commodity groups were removed from further review.2-22 2.1.4.6.2 Staff Evaluation The staff reviewed the applicant's approach to the scoping of structures relied upon to perform the functions described in 10 CFR 54.4(a). As part of this review, the staff discussed the methodology with the applicant, reviewed the documentation developed to support the review, and the scoping results for a sample of structures that were identified within the scope of license renewal. The applicant had identified and developed a list of plant structures and the structures intended functions through a review of UFSAR, CRL, design basis documents (DBDs), plant engineering drawings, plant operating manuals and procedures, plant walkdowns, and docketed correspondence. Each structure the applicant identified was evaluated against the criteria of 10 CFR 54.4(a)(1), (a)(2), and (a)(3). The staff reviewed selected portions of the UFSAR, CRL, database screening form, process flowchart, structural drawings, and implementing procedures to verify the adequacy of the methodology. During the scoping and screening methodology audit, the staff discussed the,' scoping methodology with the applicant and, on a sampling basis, reviewed the applicant's scoping reports, including information contained in the source documentation, for the turbine building and the intermediate building to verify that application of the methodology would provide the results as documented in the LRA. The staff reviewed the applicant's methodology for ' identifying structures meeting the scoping criteria as defined in the Rule. The staff verified that the applicant had identified and used pertinent engineering and licensing information in order to determine that the turbine building and the intermediate building are required to be within the scope of license renewal. As part of the review process, the staff evaluated the intended functions identified for the turbine building and the intermediate building and the components, the basis for inclusion of the intended function, and the process used to identify each of the component types. 2.1.4.6.3 Conclusion On the basis of its review of information in the LRA, scoping implementing procedures, and a sampling review of structural scoping results, the staff concludes that the applicant's metho,dology for the scoping of the structures within the scope of license renewal is in accordance with the requirements of 10 CFR 54.4, and therefore, is acceptable. 2.1.4.7 Electrical Component Scoping 2.1.4.7.1 Technical Information in the Application LRA Section 2.1.1, "Introduction," states that the scoping process for electrical and instrumentation and control (I&C) systems was performed in a manner similar to the scoping process that was applied to mechanical systems and structures. Electrical and I&C components within the in-scope mechanical systems and the in-scope electrical and I&C systems were , included within the scope of license renewal, regardless of the intended function of the ' component, which is the result of a "bounding" approach for the review of electrical components. LRA Section 2.1.6.1 states that after the scoping of electrical and I&C components was performed, the in-scope electrical components were categorized into electrical commodity groups. The staff noted that the commodity groups include similar electrical and I&C components common characteristics and that component level intended functions of the commodity grOIlJPS were identified. That staff noted that during the screening process, some commodity groups were removed from further review. 2-22 2.1.4.7.2 Staff Evaluation The staff evaluated LRA Sections 2.1.1, 2.1.5.5, and 2.5, and the applicant's implementing procedures, bases documents, and AMR reports that governed the electrical component scoping methodology. Based on its review, the staff finds that the applicant reviewed the electrical and I&C systems in accordance with the requirements of 10 CFR 54.4 and correctly determined which systems are to be included within the scope of license renewal. The staff noted that during the scoping process, the applicant used the UFSAR, DBDs, plant engineering drawings, docketed correspondence, plant specifications, and the CRL in'making its determination. All electrical and I&C components contained in license renewal systems and electrical systems contained in mechanical or structural systems were included within the scope of license renewal.The applicant performed a review of fuse holders as a commodity group. The applicant reviewed the CRL, plant drawings, and performed walkdowns to determine the fuse holders to be included within the scope of license renewal. The applicant reviewed the UFSAR, design records, procedures, corrective action program, and industry operating experience to determine if the application of tie-wraps had been credited for tie-wrap use, or if nonsafety-related tie-wraps could affect a safety-related function. The applicant did not identify any tie-wraps to be included within the scope of license renewal. The staff reviewed selected portions of the applicant's data sources and selected several examples of components for which the applicant demonstrated the process used to determine the electrical components that were within the scope of license renewal.2.1.4.7.3 Conclusion On the basis of its review of information contained in the LRA, scoping implementing procedures, scoping bases documents, and a sampling review of electrical scoping results, the staff concludes that the applicant's methodology for the scoping of electrical components within the scope of license renewal is in accordance with the requirements of 10 CFR 54.4, and therefore, is acceptable. 2.1.4.8 Scoping Methodology Conclusion On the basis of its review of the LRA and the scoping implementing procedures, the staff concludes that the applicant's scoping methodology is consistent with the guidance contained in the SRP-LR and identified those SSCs (1) that are safety-related, (2) whose failure could affect safety-related functions, and (3) that are necessary to demonstrate compliance with the NRC's regulations for fire protection (FP), EQ, PTS ATWS, and SBO. The staff concludes that the applicant's scoping 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 Technical Information in the Application LRA Section 2.1.6, "Screening Procedure," describes the process for determining which components and structural elements require an AMR. LRA Section 2.1.6.1 states that screening identifies SCs within the scope of license renewal that perform an intended function, as described in 10 CFR 54.4, without moving parts or without a change in configuration or properties, and that 2-23 2.1.4.7.2 Staff Evaluation The staff evaluated LRA Sections 2.1.1, 2.1.5.5, and 2.5, and the applicant's implementing procedures, bases documents, and AMR reports that governed the electrical component scoping methodology. Based on its review, the staff finds that the applicant reviewed the electrical and I&C systems in accordance with the requirements of 10 CFR 54.4 and correctly determined which systems are to be included within the scope of license renewal. The staff noted that during the scoping process, the applicant used the UFSAR, DBDs, plant engineering drawings, docketed correspondence, plant specifications, and the CRL in'making its determination. All electrical and I&C components contained in license renewal systems and electrical systems contained in mechanical or structural systems were included within the scope of license renewal. The applicant performed a review of fuse holders as a commodity group. The applicant reviewed the CRL, plant drawings, and performed walkdowns to determine the fuse holders to be included within the scope of license renewal. The applicant reviewed the UFSAR, design records, procedures, corrective action program, and industry operating experience to determine if the application of tie-wraps had been credited for tie-wrap use, or if nonsafety-related tie-wraps could affect a safety-related function. The applicant did not identify any tie-wraps to be included within the scope of license renewal. The staff reviewed selected portions of the applicant's data sources and selected several examples of components for which the applicant demonstrated the process used to determine the electrical components that were within the scope of license renewal. 2.1.4.7.3 Conclusion On the basis of its review of information contained in the LRA, scoping implementing procedures, scoping bases documents, and a sampling review of electrical scoping results, the staff concludes that the applicant's methodology for the scoping of electrical components within the scope of license renewal isin accordance with the requirements of 10 CFR 54.4, and therefore, is acceptable. . 2.1.4.8 Scoping Methodology Conclusion On the basis of its review of the LRA and the scoping implementing procedures, the staff concludes that the applicant's scoping methodology is consistent with the guidance contained in the SRP-LR and identified those SSCs (1) that are safety-related, (2) whose failure could affect safety-related functions, and (3) that are necessary to demonstrate compliance with the NRC's regulations for fire protection (FP), EO, PTS ATWS, and SBO. The staff concludes that the applicant's scoping 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 Technical Information in the Application LRA Section 2.1.6, "Screening Procedure," describes the process for determining which components and structural elements require an AMR. LRA Section 2.1.6.1 states that screening identifies SCs within the scope of license renewal that perform an intended function, as described in 10 CFR 54.4, without moving parts or without a change in configuration or properties, and that 2-23 are not subject to replacement based on a qualified life or specified time period. The applicant's screening process determined the SCs subject to an AMR by:* Listing the in-scope SCs by component type using the scoping results for a particular system or structure* "Screening" the component types for the passive and long-lived criteria* Identifying the intended function(s) performed by the passive and long-lived SCs by component type for the in-scope system or structure The result was a tabulation of the in-scope passive long-lived SCs that perform intended functions and therefore require an AMR. The applicant stated that it screened SCs in accordance with the recommendations of NEI 95-10 and that "active" and "short-lived" determinations were made consistent with NEI 95-10. Accordingly, the applicant explained it "screened out" components or structural elements that were either active or subject to replacement based on a qualified life and determined that these SCs were not subject to an AMR.2.1.5.1.2 Staff Evaluation Pursuant to 10 CFR 54.21, each LRA must contain an IPA that identifies SCs within the scope of license renewal that are subject to an AMR. The IPA must identify components that perform an intended function without moving parts or a change in configuration or properties (passive), and also identify components that are not subject to periodic replacement based on a qualified life or specified time period (long-lived). The IPA includes a description and justification of the methodology used to determine the passive and long-lived SCs, and a demonstration that the effects of aging on those SCs will be adequately managed so that the intended function(s) will be maintained under all design conditions imposed by the plant specific CLB for the period of extended operation. The staff reviewed the methodology used by the applicant to determine if mechanical and structural components and electrical commodity groups within the scope of license renewal i should be subject to an AMR. The applicant implemented a process for determining which SCs were subject to an AMR in accordance with the requirements of 10 CFR 54.21 (a)(1). In LRA Section 2.1.6, the applicant discussed these screening activities as they related to the component types and commodity groups within the scope of license renewal.The screening process evaluated the component types and commodity groups included within the scope of license renewal to determine which ones were long-lived and passive and therefore subject to an AMR. The staff reviewed Section 2.3, "Scoping and Screening Results: Mechanical;" Section 2.4, "Scoping and Screening Results: Structures;" and Section 2.5, "Scoping and Screening Results: Electrical Systems/Commodity Groups" of the LRA that provided the results of the process used to identify component types and commodity groups subject to an AMR. The staff also reviewed the screening results reports for the main steam system, the decay heat removal system, the turbine building, and the intermediate building.The applicant provided the staff with a detailed discussion of the processes used for each discipline and provided administrative documentation that described the screening methodology. Specific methodology for mechanical, electrical, and structural is discussed below.2-24 are not subject to replacement based on a qualified life or specified time period. The applicant's screening process determined the SCs subject to an AMR by: *. Listing the in-scope SCs by component type using the scoping results for a particular system or structure

  • "Screening" the component types for the passive and long-lived criteria
  • Identifying the intended function(s) performed by the passive and long-lived SCs by component type for the in-scope system or structure The result was a tabulation of the in-scope passive long-lived SCs that perform intended functions and therefore require an AMR. The applicant stated that it screened SCs in accordance with the recommendations of NEI 95-10 and that "active" and "short-lived" determinations were made consistent with NEI 95-10. Accordingly, the applicant explained it "screened out" components or structural elements that were either active or subject to replacement based on a qualified life and determined that these SCs were not subject to an AMR. 2.1.5.1.2 Staff Evaluation Pursuant to 10 CFR 54.21, each LRA must contain an IPA that identifies SCs within the scope of license renewal that are subject to an AMR. The IPA must identify components that perform an intended function without moving parts or a change in configuration or properties (passive), and also identify components that are not subject to periodic replacement based on a qualified life or specified time period (long-lived).

The IPA includes a description and justification of the methodology used to determine the passive and long-lived SCs, and a demonstration that the effects of aging on those SCs will be adequately managed so that the intended function(s) will be maintained under all design conditions imposed by the plant specific CLB for the period of extended operation. The staff reviewed the methodology used by the applicant to determine if mechanical and . structural components and electrical commodity groups within the scope of license renewal! should be subject to an AMR. The applicant implemented a process for determining which ?CS were subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1). In LRA Section 2.1.6, the applicant discussed these screening activities as they related to the component types and commodity groups within the scope of license renewal. The screening process evaluated the component types and commodity groups included within the scope of license renewal to determine which ones were long-lived and passive and therefore subject to an AMR. The staff reviewed Section 2.3, "Scoping and Screening Results: Mechanical;" Section 2.4, "Scoping and Screening Results: Structures;" and Section 2.5, "Scoping and Screening Results: Electrical Systems/Commodity Groups" of the LRA that provided the results of the process used to identify component types and commodity groups subject to an AMR. The staff also reviewed the screening results reports for the main steam system, the decay heat removal system, the turbine building, and the intermediate building. The applicant provided the staff with a detailed discussion of the processes used for each discipline and provided administrative documentation that described the screening methodology. Specific methodology for mechanical, electrical, and structural is discussed below. 2-24 2.1.5.1.3 Conclusion On the basis of its review of the screening methodology contained in the LRA, the screening implementing procedures, and a sampling of screening results, the staff concludes that the applicant's screening methodology was consistent with the guidance contained in the SRP-LR and was capable of identifying passive, long-lived components in scope of license renewal that are subject to an AMR. The staff determined that the applicant's process for determining which component types and commodity groups are subject to an AMR is consistent with the requirements of 10 CFR 54.21.2.1.5.2 Mechanical Component Screening2.1.5.2.1 Technical Information in the Application LRA Section 2.1.6.1, "Identification of Structures and Components Subject to AMR," subsection"Mechanical Systems," describes the screening methodology for identifying passive and long-lived mechanical components and their support structures that are subject to an AMR.According to the LRA, the mechanical system screening process began with the results from the scoping process. For in-scope mechanical systems, the applicant developed written system descriptions and used system flow diagrams to identify the in-scope system boundary which resulted in the license renewal boundary drawing for the mechanical system. The applicant states that it reviewed the system boundary drawings to identify the passive, long-lived components. The identified passive, long-lived components were then entered into the license renewal database.Component listings from the CRL were also reviewed to confirm that all system components were considered. In cases where the system flow diagram did not provide sufficient detail, such as for some large vendor supplied components (e.g., compressors, emergency diesel generators), the associated component drawings or vendor manuals were also reviewed. In addition, plant walkdowns were performed when required for confirmation. The identified list of passive, long-lived system components was compared to previous license renewal applications containing a similar system. Mechanical components were screened with the system in which they were scoped. For heat exchangers and coolers that are in scope only for 10 CFR 54.4 (a)(2) spatial interactions, the materials, environments and aging effects on both sides of the heat transfer surfaces were evaluated with the system that performs the cooling function. For heat exchangersand coolers that are in scope for 10 CFR 54.4(a)(2) only, each side of the heat exchanger or cooler was evaluated separately with the system associated with the process environment. 2.1.5.2.2 Staff Evaluation The staff evaluated the mechanical screening methodology discussed and documented in LRA Section 2.1.6.1, the implementing guidance documents, the AMR reports, and the license renewal drawings. The staff noted that the applicant reviewed each system evaluation boundary asillustrated on P&IDs to identify passive and long-lived components. The staff noted that within the system evaluation boundaries, all passive, long-lived components that perform or support an intended function were subject to an AMR. The staff noted that the applicant documented its review in the AMR reports that contain information such as the information sources reviewed and the system intended functions.The staff reviewed the results of the applicant's boundary evaluations and discussed the process with the applicant. The staff verified that mechanical system evaluation boundaries were established for each system within the scope of license renewal and that the boundaries were determined by mapping the system intended function boundary onto P&IDs. The staff noted that 2-25 2.1.5.1.3 Conclusion On the basis of its review of the screening methodology contained in the LRA, the screening implementing procedures, and a sampling of screening results, the staff concludes that the applicant's screening methodology was consistent with the guidance contained in the SRP-LR and was capable of identifying passive, long-lived components in scope of license renewal that are subject to an AMR. The staff determined that the applicant's process for determining which component types and commodity groups are subject to an AMR is consistent with the requirements of 10 CFR 54.21. 2.1.5.2 Mechanical Component Screening 2.1.5.2.1 Technical Information in the Application LRA Section 2.1.6.1, "Identification of Structures and Components Subject to AMR," subsection "Mechanical Systems," describes the screening methodology for identifying passive and long-lived mechanical components and their support structures that are subject to an AMR. According to the LRA, the mechanical system screening process began with the results from the scoping process. For in-scope mechanical systems, the applicant developed written system descriptions and used system flow diagrams to identify the in-scope system boundary which resulted in the license renewal boundary drawing for the mechanical system. The applicant states that it reviewed the system boundary drawings to identify the passive, long-lived components. The identified passive, long-lived components were then entered into the license renewal database. Component listings from the CRL were also reviewed to confirm that all system components were considered. In cases where the system flow diagram did not provide sufficient detail, such as for some large vendor supplied components (e.g., compressors, emergency diesel generators), the associated component drawings or vendor manuals were also reviewed. In addition, plant walkdowns were performed when required for confirmation. The identified list of passive, long-lived system components was compared to previous license renewal applications containing a similar system. Mechanical components were screened with the system in which they were scoped. For heat exchangers and coolers that are in scope only for 10 CFR 54.4 (a)(2) spatial interactions, the materials, environments and aging effects on both sides of the heat transfer surfaces were evaluated with the system that performs the cooling function. For heat exchangers and coolers that are in scope for 10 CFR 54.4(a)(2) only, each side of the heat exchanger or cooler was evaluated separately with the system associated with the process environment. 2.1.5.2.2 Staff Evaluation The staff evaluated the mechanical screening methodology discussed and documented in LRA Section 2.1.6.1, the implementing guidance documents, the AMR reports, and the license renewal drawings. The staff noted that the applicant reviewed each system evaluation boundary as illustrated on P&IDs to identify passive and long-lived components. The staff noted that within the system evaluation boundaries, all passive, long-lived components that perform or support an intended function were subject to an AMR. The staff noted that the applicant documented its review in the AMR reports that contain information such as the information sources reviewed and the system intended functions. The staff reviewed the results of the applicant's boundary evaluations and discussed the process with the applicant. The staff verified that mechanical system evaluation boundaries were established for each system within the scope of license renewal and that the boundaries were determined by mapping the system intended function boundary onto P&IDs. The staff noted that 2-25 the applicant reviewed the components within the system intended function boundary to determine if the component supported the system intended function. The staff also noted that those components that supported the system intended function were reviewed by the applicant to determine if the component was passive and long-lived, and therefore subject to an AMR.The staff reviewed selected portions of design criteria documents, UFSAR, system DBDs, plant drawings, and selected AMR reports. The staff conducted detailed discussions with the applicant's license renewal team and reviewed documentation pertinent to the screening process.The staff assessed whether the mechanical screening methodology outlined in the LRA and procedures was appropriately implemented, and if the scoping results were consistent with CLB requirements. During the scoping and screening methodology audit, the staff discussed thel screening methodology and, on a sampling basis, reviewed the applicant's screening reports for the main steam and decay heat removal systems to verify proper implementation of the screening process. Based on these audit activities, the staff did not identify any discrepancies between the methodology documented and the implementation results.2.1.5,2.3 Conclusion Based on its review of the LRA, the screening implementing procedures, and a sample of the main steam and decay heat removal systems screening results, the staff concludes that the applicant's mechanical component screening methodology is consistent with SRP-LR guidance.The staff concludes that the applicant's methodology for identification of passive, long-lived mechanical components within the scope of license renewal and subject to an AMR is in accordance with the requirements of 10 CFR 54.21(a)(1), and therefore, is acceptable. 2.1.5.3 Structural Component Screening 2.1.5.3.1 Technical Information in the Application LRA Section 2.1.6.1, "Identification of Structures and Components Subject to AMR," subsection"Structures," states that the structural component screening process began with consideration of the results from the structural scoping process. According to the LRA, drawings of the structures identified from the scoping process were reviewed to identify the passive, long-lived structures and components, and were entered into the license renewal database. For these structures, written descriptions were carried over from those prepared for the scoping portion of the process.Component listings from the component record list were also reviewed to confirm that all structural components were considered, and plant walkdowns were also conducted for additional confirmation. Additionally, the applicant benchmarked the identified list of passive, long-lived structures and components against previous license renewal applications for added assurance of completeness. 2.1.5.3.2 Staff Evaluation The staff reviewed the applicant's methodology for identifying structural components that are subject to an AMR as required in 10 CFR 54.21(a)(1). As part of this review, the staff discussed the methodology with the applicant, reviewed the documentation developed to support the activity, and evaluated the screening results for a sample of structures that were identified within the scope of license renewal.In addition, the staff reviewed the applicant's methodology used for structural screening described in LRA Section 2.1.6.1, and in the applicant's implementing guidance. The staff finds that the 2-26 the applicant reviewed the components within the system intended function boundary to determine jf the component supported the system intended function. The staff also noted that those components that supported the system function were reviewed by the applicant to determine if the component was passive and long-lived, and therefore subject to an AMR. The staff reviewed selected portions of design criteria documents, UFSAR, system DBDs, plant drawings, and selected AMR reports. The staff conducted detailed discussions with the applicant's license renewal team and reviewed documentation pertinent to the screening process. The staff assessed whether the mechanical screening methodology outlined in the LRA ana procedures was appropriately implemented, and if the sGoping results were consistent with :CLB requirements. During the scoping and screening methodology audit, the staff discussed screening methodology and, on a sampling basis, reviewed the applicant's screening reports for the main steam and decay heat removal systems to verify proper implementation of the screening 'process. Based on these audit activities, the staff did not identify any discrepancies between the methodology documented and the implementation results. 2.1.5.2.3 Conclusion Based on its review of the LRA, the screening implementing procedures, and a sample of the main steam and decay heat removal systems screening results, the staff concludes that the applicant's mechanical component screening methodology is consistent with SRP-LR guidance. The staff concludes that the applicant's methodology for identification of passive; long-lived mechanical components within the scope of license renewal and subject to an AMR is in accordance with the requirements of 10 CFR 54.21(a)(1), and therefore, is acceptable. 2.1.5.3 Structural Component Screening 2.1.5.3.1 Technical Information in the Application LRA Section 2.1.6.1, "Identification of Structures and Components Subject to AMR," subsection "Structures," states that the structural component screening process began with consideration of the results from the structural scoping process. According to the LRA, drawings of the structures identified from the scoping process were reviewed to identify the passive, long-lived structures and components, and were entered into the license renewal database. For these structures, . written descriptions were carried over from those prepared for the scoping portion of the process. Component listings from the component record list were also reviewed to confirm that all structural components were considered, and plant walkdowns were also conducted for additional confirmation. Additionally, the applicant benchmarked the identified list of passive, long-lived structures and components against previous license renewal applications ,for added assuralilce of completeness. 2.1.5.3.2 Staff Evaluation The staff reviewed the applicant's methodology for identifying structural components that are subject to an AMR as required in 10 CFR 54.21(a)(1). As part of this review, the staff discussed the methodology with the applicant, reviewed the documentation developed to support the activity, and evaluated the screening results for a sample of structures that were identified within the scope of license renewal. In addition, the staff reviewed the applicant's methodology used for structural screening described in LRA Section 2.1.6.1, and in the applicant's implementing guidance. The staff finds that the 2-26 applicant performed the screening review in accordance with the implementing guidance and captured pertinent structure design information, components, materials, environments, and aging effects. The applicant confirmed the results of their review with a complete peer review on every item identified. The staff confirmed 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. The staff reviewed the applicant's structural commodities scoping report, which listed structural components, grouped as commodities based on materials of construction. The primary task performed by the applicant during the screening process was to evaluate structural components to identify intended functions as they relate to license renewal. The applicant provided the staff with additional information that described the screening methodology, as well as the implementing procedures and database forms used to complete it.The staff reviewed selected portions of the UFSAR, DBDs, design drawings, general site layout drawings, implementing procedures, and database forms. The staff conducted detailed discussions with the applicant's license renewal team and reviewed documentation pertinent to the screening process. The staff assessed whether the screening methodology outlined in the LRA and implementing procedures were appropriately implemented and if the scoping results were consistent with CLB requirements. During the scoping and screening methodology audit the staff discussed the screening methodology and, on a sampling basis, reviewed the applicant's screening reports for the turbine building and the intermediate building to verify proper implementation of the screening process. Based on these onsite review activities, the staff did not identify any discrepancies between the methodology documented and the implementation results.2.1.5.3.3 Conclusion On the basis of its review of information contained in the LRA, selected portions of the UFSAR, DBDs, design drawings, general site layout drawings, implementing procedures, database forms, the applicant's detailed screening implementing procedures, and a sampling review of structural screening results, the staff concludes that the applicant's methodology for the screening of structural components within the scope of license renewal and subject to an AMR is in accordance with the requirements of 10 CFR 54.21(a)(1), and therefore, is acceptable. 2.1.5.4 Electrical Component Screening 2.1.5.4.1 Summary of Technical Information in the Application LRA Section 2.1.6.1, "Identification of Structures and Components Subject to AMR," states that electrical and I&C components within the in-scope electrical, I&C, and mechanical systems, useda bounding approach for screening. Electrical and I&C components were assigned to commodity groups based on information provided in NEI 95-10 Appendix B, SRP-LR, the EPRI License Renewal Electrical Handbook, and the plant's configuration. The commodity groups subject to AMR were identified by applying the criteria of 10 CFR 54.21(a)(1)(i). The staff notes that insulated cables and connections located inside active component enclosures are considered part of the active component, and are maintained along with the other subcomponents and piece-parts and therefore, these cables, connections, and other subcomponents are not subject to an AMR.The applicant screened the remaining commodity groups by applying the criteria of 10 CFR 54.21(a)(1)(ii). Components in the EQ program were screened out and not subject to AMR. The remaining commodity groups were evaluated to determine those groups subject to AMR based on industry operating experience and plant configurations. Electrical commodities 2-27 applicant performed the review in accordance with the implementing guidance and captured pertinent structure design information, components, materials, environments, and aging effects. The applicant confirmed the results of their review with a complete peer review on every item identified. The staff confirmed 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. The staff reviewed the applicant's structural commodities scoping report, which listed structural components, grouped as commodities based on materials of construction. The primary task performed by the applicant during the screening process was to evaluate structural components to identify intended functions as they relate to license renewal. The applicant provided the staff with additional information that described the screening methodology, as well as the implementing procedures and database forms used to complete it. . The staff reviewed selected portions of the UFSAR, DBDs, design drawings, general site layout drawings, implementing procedures, and database forms. The staff conducted detailed discussions with the applicant's license renewal team and reviewed documentation pertinent to the screening process. The staff assessed whether the screening methodology outlined in the LRA and implementing procedures were appropriately implemented and if the scoping results were consistent with CLB requirements. During the scoping and screening methodology audit the staff discussed the screening methodology and, on a sampling basis, reviewed the applicant's screening reports for the turbine building and the intermediate building to verify proper implementation of the screening process. Based on these onsite review activities, the staff did not identify any discrepancies between the methodology documented and the implementation results. 2.1.5.3.3 Conclusion On the basis of its review of information contained in the LRA, selected portions of the UFSAR, DBDs, design drawings, general site layout drawings, implementing procedures, database forms, the applicant's detailed screening implementing procedures, and a sampling review of structural results, the staff concludes that the applicant's methodology for the screening of structural components within the scope of license renewal and subject to an AMR is in accordance with the requirements of 10 CFR 54.21(a)(1), and therefore, is acceptable. 2.1.5.4 Electrical Component Screening 2.1.5.4.1 Summary of Technical Information in theApplication LRA Section 2.1.6.1, "Identification of Structures and Components Subject toAMR," states that electrical and I&C components within the in-scope electrical, I&C, and mechanical systems, used a bounding approach for screening. Electrical and I&C components were assigned to commodity groups based on information provided in NEI 95-10 Appendix B, SRP-LR, the EPRI License Renewal Electrical Handbook, and the plant's configuration. The commodity groups subject to AMR were identified by applying the criteria of 10 CFR 54.21(a)(1)(i). The staff notes that insulated cables and connections located inside active component enclosures are considered part of the active component, and are maintained along with the other subcomponents and piece-parts and therefore, these cables, connections, and other subcomponents are not subject to an AMR. The applicant screened the remaining commodity groups by applying the criteria of 10 CFR 54.21(a)(1)(ii). Components in the EQ program were screened out and not subject to AMR. The remaining commodity groups were evaluated to determine those groups subject to AMR based on industry operating experience and plant configurations. Electrical commodities 2-27 that require an AMR are individual passive electrical commodities that are not part of a larger active assembly, and passive commodity groups that are not subject to replacement. The applicant identified 13 passive electrical commodity groups that meet the 10 CFR 54.21(a)(1)(i) criterion (i.e., components that perform an intended function without rmoving parts or without a change in configuration). The applicant screened the 13 commodity groups and eliminated those groups that did not have a license renewal intended function and were subject to replacement based on a qualified life for a specified time period in accordance with the criteria of 10 CFR 54.21(a)(1)(ii). The applicant identified eight electrical commodity groups which were subject to AMR: (1) Cable connections (metallic parts)(2) Connector contacts for electrical connectors exposed to borated water leakage (3) Fuse holders (4) High-voltage insulators (5) Insulated cables and connections (6) Metal enclosed bus (7) Switchyard bus and connections (8) Transmission conductors and connections 2.1.5.4.2 Staff Evaluation The staff reviewed the applicant's methodology used for electrical component screening in LRA Sections 2.1.6.1 and 2.5.2, "Electrical Commodity Groups," the applicant's implementing procedures, bases documents, and electrical 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 information contained in NEI 95-10 Appendix B, SRP-LR, EPRI License Renewal Electrical Handbook, plant documents and drawings, and the CRL as data sourceJs to identify the electrical and I&C components. The applicant identified 13 commodity groups which were determined to meet the passive criteria in accordance with NEI 95-10. The applicant evaluated the identified passive commodities todecide whether or not they were subject to replacement based on a qualified life or specified timeperiod (short-lived), or not subject to replacement based on a qualified life or specified timeperiod (long-lived). The remaining passive, long-lived components were determined to be subject to an AMR. The staff reviewed the screening of selected components to confirm the correct implementation of the methodology. The staff reviewed the LRA, procedures, electrical drawings, and a sample of the results of the screening methodology. The staff determined that the applicant's methodology was consistent with the description provided in the LRA and the applicant's implementing procedures. 2.1.5.4.3 Conclusion On the basis of its review of the information contained in the LRA, the applicant's screening implementing procedures, and a sampling review of the electrical screening results, the staffconcludes that the applicant's methodology for the screening of electrical components within the scope of license renewal and subject to an AMR is in accordance with the requirements of 10 CFR 54.21(a)(1). 2-28 i that require an AMR are individual passive electrical commodities that are not part of a active assembly, and passive commodity groups that are not subject to replacement. The applicant identified 13 passive electrical commodity groups that meet the 10 CFR 54.21(a)(1 )(i) criterion (Le., components that perform an intended function without roving parts or without a change in configuration). The applicant screened the 13 commodity groups and eliminated those groups that did not have a license renewal intended function and were subject to replacement based on a qualified life for a specified time period in accordance with the critJria of 10 CFR 54.21(a)(1)(ii). The applicant identified eight electrical commodity groups which subject to AMR: ii (1) Cable connections (metallic parts) (2) Connector contacts for electrical connectors exposed to borated water leakage (3) Fuse holders (4) High-voltage insulators (5) Insulated cables and connections (6) Metal enclosed bus (7) Switchyard bus and connections (8) Transmission conductors and connections 2.1.5.4.2 Staff Evaluation The staff reviewed the applicant's methodology used for electrical component screening in LRA Sections 2.1.6.1 and 2.5.2, "Electrical Commodity Groups," the applicant's implementing !: procedures, bases documents, and electrical AMR reports. The applicant used the process described in these documents to identify the electrical commodity groups subject tb AMR. The applicant used the information contained in NEI 95-10 Appendix B, SRP-LR, EPRI License . I Renewal Electrical Handbook, plant documents and drawings, and the CRL as data sources to . , identify the electrical and I&C components. . . I The applicant identified 13 commodity groups which were determined to meet the passive in accordance with NEI 95-10. The applicant evaluated the identified passive commodities to decide whether or not they were subject to replacement based on a qualified life .or time period (short-lived), or not subject to replacement based on a qualified life or specified timeliperiod (long-lived). The remaining passive, long-lived components were determined to be subject to an AMR. The staff reviewed the screening of selected components to confirm the correct implementation of the methodology. ,I The staff reviewed the LRA, procedures, electrical drawings, and a sample of the results screening methodology. The staff determined that the applicant's methodology was with the description provided in the LRA and the applicant's implementing procedures. . 2.1.5.4.3 Conclusion On the basis of its review of the information contained in the LRA, the applicant's screening implementing procedures, and a sampling review of the electrical screening results, the staff concludes that the applicant's methodology for the screening of electrical components withib the scope of license renewal and subject to an AMR is in accordance with the requirements of I: 10 CFR 54.21(a)(1). I' 2-28 2.1.5.5 Screening Methodology Conclusion On the basis of its review of the LRA, the screening implementing procedures, discussions with the applicant's staff, and a sample review of screening results, the staff determined that the applicant's screening methodology was consistent with the guidance contained in the SRP-LR and identified those passive, long-lived components within the scope of license renewal that are subject to an AMR. The staff concluded that the applicant's screening methodology is consistent with the requirements of 10 CFR 54.21(a)(1), and therefore, is acceptable.

2.1.6 Summary

of Evaluation Findings On the basis of its review of the information in LRA Section 2.1, the supporting information in the scoping and screening implementing procedures and reports, the information presented during the scoping and screening methodology audit, and the applicant's responses to the staff's RAIs, the staff confirms that the applicant's scoping and screening methodology was consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff also concludes that the applicant's description and justification of its scoping and screening methodology are adequate to meet the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1), and, therefore, is acceptable. Based on its review, the staff concludes that the applicant's methodology for identifying systems and structures within the scope of license renewal and SCs requiring an AMR is acceptable. 2.2 Plant-Level Scoping Results

2.2.1 Introduction

LRA Section 2.1 describes the methodology for identifying systems and structures within the scope of license renewal. In LRA Section 2.2, the applicant used the scoping methodology to determine which systems and structures must be included within the scope of license renewal.The staff reviewed the plant-level scoping results to determine whether the applicant has properly identified the following three groups:

  • Systems and structures relied upon to mitigate DBEs, as required by 10 CFR 54.4(a)(1).
  • Systems and structures the failure of which could prevent satisfactory accomplishment of any safety-related functions, as required by 10 CFR 54.4(a)(2).

Systems and structures relied on in safety analyses or plant evaluations to performfunctions required by regulations referenced in 10 CFR 54.4(a)(3).

2.2.2 Summary

of Technical Information in the Application LRA Table 2.2-1 lists those mechanical systems, electrical and I&C systems, and structures that are within the scope of license renewal. Also in LRA Table 2.2-1, the applicant listed the systems and structures that do not meet the criteria specified in 10 CFR 54.4(a) and are excluded from the scope of license renewal. Based on the DBEs considered in the 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 54.4.2-29 2.1.5.5 Screening Methodology Conclusion On the basis of its review of the LRA, the screening implementing procedures, discussions with the applicant's staff, and a sample review of screening results, the staff determined that the applicant's screening methodology was consistent with the guidance contained in the SRP-LR and identified those passive, long-lived components within the scope of license renewal that are subject to an AMR. The staff concluded that the applicant's screening methodology is consistent with the requirements of 10 CFR 54.21(a)(1), and therefore, is acceptable.

2.1.6 Summary

of Evaluation Findings On the basis of its review of the information in LRA Section 2.1, the supporting information in the scoping and screening implementing procedures and reports, the information presented during the scoping and screening methodology audit, and the applicant's responses to the staff's RAls, the staff confirms that the applicant's scoping and screening methodology was consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff also concludes that the applicant's description and justification of its scoping and screening methodology are adequate to meet the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1), and, therefore, is acceptable. Based on its review, the staff concludes that the applicant's methodology for identifying systems and structures within the scope of license renewal and SCs requiring an AMR is acceptable. 2.2 Plant-level Scoping Results 2.2.1 Introduction LRA Section 2.1 describes the methodology for identifying systems and structures within the scope of license renewal. In LRA Section 2.2, the applicant used the scoping methodology to determine which systems and structures must be included within the scope of license renewal. The staff reviewed the plant-level scoping results to determine whether the applicant has properly identified the following three groups:

  • Systems and structures relied upon to mitigate DBEs, as required by 10 CFR 54.4(a)(1).
  • Systems and structures the failure of which could prevent satisfactory accomplishment of any safety-related functions, as required by 10 CFR 54.4(a)(2).
  • Systems and structures relied on in safety analyses or plant evaluations to perform functions required by regulations referenced in 10 CFR 54.4(a)(3).

2.2.2 Summary

of Technical Information in the Application LRA Table 2.2-1 lists those mechanical systems, electrical and I&C systems, and structures that are within the scope of license renewal. Also in LRA Table 2.2-1, the applicant listed the systems and structures that do not meet the criteria specified in 10 CFR 54.4(a) and are excluded from the scope of license renewal. Based on the DBEs considered in the 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. 2-29

2.2.3 Staff

Evaluation The purpose of the staffs evaluation was to determine whether the applicant properly identified the systems and structures within the scope of license renewal in accordance with 10 CFR 54.4.The staffs review and evaluation of the applicant's scoping and screening methodology is provided in SER Section 2.1. In order to confirm that the applicant properly implemented its methodology in accordance with 10 CFR 54.4, the staffs review focused on the implementation results the applicant provided in LRA Table 2.2-1 to confirm that there were no omissions of plant-level systems and structures within the scope of license renewal.The staff reviewed selected systems and structures that the applicant did not identify as being within the scope of license renewal to confirm whether these excluded systems and structures performed any intended functions requiring their inclusion within the scope of license renewal.The staff's review of the applicant's implementation was conducted in accordance with the guidance in SRP-LR Section 2.2.The staff reviewed LRA Section 2.2, the UFSAR supporting information, and applicable license renewal drawings to determine whether the applicant failed to identify any systems and structures that are required to be included within the scope of license renewal. The staff finds no omissions.

2.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant has appropriately identifiedl the systems and structures within the scope of license renewal in accordance with 10 CFR 54.4.2.3 Scoping and Screening Results: Mechanical Systems This section documents the staff s review of the applicant's scoping and screening results for mechanical systems. Specifically, this section describes the following mechanical systems:* Reactor vessel, internals, and reactor coolant system* Engineered safety features systems* Auxiliary systems* Steam and power conversion systems The staff evaluation of the mechanical system scoping and screening results applies to all mechanical systems reviewed. Those systems that required requests for additional information (RAIs) to be generated (if any) include an additional staff evaluation which specifically addressesthe applicant's responses to the RAI(s).In accordance with the requirement 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 verify that the applicant identified all mechanical system SCs that met the scoping criteria and were subject to an AMR, and to confirm that there were no omissions. 2-30 2.2.3 Staff Evaluation The purpose of the staffs evaluation was to determine whether the applicant properly identified the systems and structures within the scope of license renewal in accordance with 10 CFR 1'54.4. The staffs review and evaluation of the applicant's scoping and screening methodology is . provided in SER Section 2.1. In order to confirm that the applicant properly implemented its methodology in accordance with 10 CFR 54.4, the staffs review focused on the implementation results the applicant provided in LRA Table 2.2-1 to confirm that there were no omissions of level systems and structures within the scope of license renewal. The staff reviewed selected systems and structures that the applicant did not identify as being within the scope of license renewal to confirm whether these excluded systems and structures performed any intended functions requiring their inclusion within the scope of license The staff's review of the applicant's implementation was conducted in accordance with the ' guidance in SRP-LR Section 2.2. . The staff reviewed LRA Section 22, the UFSAR supporting information, and applicable license renewal drawings to determine whether the applicant failed to identify any systems and structures that are required to be included within the scope of license renewal. The staff finds no omissions.

2.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant has appropriately identifiedl the systems and structures within the scope of license renewal in accordance with 10 CFR 54.4. 2.3 Scoping and Screening Results: Mechanical Systems This section documents the staffs review of the applicant's scoping and screening results for mechanical systems. Specifically, this section describes the following mechanical systems: ,:."

  • Reactor vessel, internals, and reactor coolant system .
  • Engineered safety features systems
  • Auxiliary systems
  • Steam and power conversion systems The staff evaluation of the mechanical system scoping and screening results applies to all mechanical systems reviewed.

Those systems that required requests for additional (RAls) to be generated (if any) include an additional staff evaluation which specifically addresses the applicant's responses to the RAI(s). . In accordance with the requirement 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 verify that the applicant identified all mechanical system SCs that met the scoping criteria and were subject to an AMR, and to confirm that there were no omissions. 2-30 The staffs evaluation was performed using the evaluation methodology described here, the guidance in SRP-LR Section 2.3, and took into account (where applicable) the system functions(s) described in the UFSAR. The objective was to determine whether the applicant identified, in accordance with 10 CFR 54.4, components and supporting structures for mechanical systems that meet the license renewal scoping criteria. Similarly, the staff evaluated theapplicant's screening results to verify that all passive, long-lived components were subject to an AMR in accordance with 10 CFR 54.21(a)(1). In its scoping evaluation, the staff reviewed the LRA, applicable sections of the UFSAR, license renewal boundary drawings, and other licensing basis documents, as appropriate, for each mechanical system within the scope of license renewal. The staff reviewed relevant licensing basis documents for each mechanical system to confirm that the applicant specified all intended functions defined by 10 CFR 54.4(a). The review then focused on identifying any components with intended functions defined by 10 CFR 54.4(a) that the applicant may have omitted from the scope of license renewal.After reviewing the scoping results, the staff evaluated the applicant's screening results. For those SCs with intended functions delineated under 10 CFR 54.4(a), the staff verified the applicant properly screened out only: (1) SCs that have functions performed with moving parts or a change in configuration or properties or (2) SCs that are subject to replacement after a qualified life or specified time period, as described in 10 CFR 54.21(a)(1). For SCs not meeting either of these criteria, the staff confirmed the remaining SCs received an AMR, as required by 10 CFR 54.21(a)(1). The staff requested additional information to resolve any omissions or discrepancies identified. The staff performed an alternate review of selected systems contained in Section 2.3.3, Auxiliary Systems, and Section 2.3.4, Steam and Power Conversion Systems. The systems selected for an alternate review were determined to have the following characteristics:

  • Low safety or low risk significance.
  • Little operating experience indicating likely passive failures.* No previous LRA experience indicating a need to perform a detailed review.For the systems selected for alternate review, the staff evaluated the system's function(s) described in the LRA and UFSAR to verify that the applicant included in the scope of license renewal all component types identified by 10 CFR 54.4(a). The staff reviewed the LRA and UFSAR to confirm that the applicant has identified the component types that are typically found within the scope of license renewal. The staff also verified that the applicant has identified the component types subject to an AMR in accordance with the requirements stated in 10 CFR 54.21 (a)(1).Those systems that received an alternate review are as follows:* 2.3.3.3 Circulating Water System* 2.3.3.7 Cranes And Hoists* 2.3.3.11 Fuel Handling And Fuel Storage System* 2.3.3.12 Fuel Oil System 2-31 The staffs evaluation was performed using the evaluation methodology described here, the guidance in SRP-LR Section 2.3, and took into account (where applicable) the system functions(s) described in the UFSAR. The objective was to determine whether the applicant identified, in accordance with 10 CFR 54.4, components and supporting structures for mechanical systems that meet the license renewal scoping criteria.

Similarly, the staff evaluated the applicant's screening results to verify that all passive, long-lived components were subject to an AMR in accordance with 10 CFR 54.21(a)(1). In its scoping evaluation, the staff reviewed the LRA, applicable sections of the UFSAR, license renewal boundary drawings, and licensing basis documents, as appropriate, for each mechanical system within the scope of license renewal. The staff reviewed relevant licensing. basis documents for each mechanical system to confirm that the applicant specified all intended functions defined by 10 CFR 54.4(a). The review then focused on identifying any components with intended functions defined by 10 CFR 54.4(a) that the applicant may have omitted from the scope of license renewal. After reviewing the scoping results, the staff evaluated the applicant's screening results. For those SCs with intended functions delineated under 10 CFR 54.4(a), the staff verified the applicant properly screened out only: (1) SCs that have functions performed with moving parts or a change in configuration or properties or (2) SCs that are subject to replacement after a qualified life or specified time period, as described in 10 CFR 54.21 (a)(1). For SCs not meeting either of these criteria, the staff confirmed the remaining SCs received an AMR, as required by 10 CFR 54.21 (a)( 1). The staff requested additional information to resolve any omissions or discrepancies identified. The staff performed an alternate review of selected systems contained in Section 2.3.3, Auxiliary Systems, and Section 2.3.4, Steam and Power Conversion Systems. The systems selected for an alternate review were determined to have the following characteristics:

  • Low safety or low risk significance.
  • Little operating experience indicating likely passive failures.
  • No previous LRA experience indicating a need to perform a detailed review. For the systems selected for alternate review, the staff evaluated the system's function(s) described in the LRA and UFSAR tq verify that the applicant included in the scope of license renewal all component types identified by 10 CFR 54.4(a). The staff reviewed the LRA and UFSAR to confirm that the applicant has identified the component types that are typically found within the scope of license renewal. The staff also verified that the applicant has identified the component types subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).

Those systems that received an alternate review are as follows:

  • 2.3.3.3
  • 2.3.3.7
  • 2.3.3.11
  • 2.3.3.12 Circulating Water System Cranes And Hoists Fuel Handling And Fuel Storage System Fuel Oil System 2-31
  • 2.3.3.13 Hydrogen Monitoring System* 2.3.3.18 Miscellaneous Floor And Equipment Drains System* 2.3.3.21 Radwaste System
  • 2.3.4.1 Condensate System* 2.3.4.2 Condensers And Air Removal System* 2.3.4.6 Main Generator And Auxiliary Systems 2.3.1 Reactor Vessel, Internals, and Reactor Coolant System LRA Section 2.3.1 describes the reactor vessel, internals, and reactor coolant system SCs subject to an AMR for license renewal. The applicant described the supporting SCs of the reactor vessel, internals, and reactor coolant system in the following LRA sections:* 2.3.1.1 Reactor coolant system* 2.3.1.2 Reactor vessel* 2.3.1.3 Reactor vessel internals* 2.3.1.4 Steam generator 2.3.1.1 Reactor Coolant System 2.3.1.1.1 Summary of Technical Information in the Application LRA Section 2.3.1.1 describes the reactor coolant system (RCS). The RCS is a normally operating system designed to circulate sub-cooled reactor coolant to transfer heat from the reactor vessel (RV) core to the secondary fluid in the once through steam generators (OTSGs).The RCS consists of RCS hot leg and cold leg piping, four reactor coolant pumps (RCPs), the pressurizer, pressurizer heaters, the pressurizer surge line, and the pressurizer spray line. The purpose of the RCS is to provide reactor coolant to the RV by either forced circulation from the RCPs or natural circulation, and to transfer the heat from the coolant to the secondary fluid ý"in the OTSGs. The coolant from the RV exits through two hot leg lines and enters the OTSGs where the heat is transferred to the secondary fluid. The primary coolant then is pumped back into the RVthrough the four cold legs by the four RCPs. The pressurizer and the pilot operated relief valve (PORV) and two pressurizer code safety valves maintain the RCS pressure within the prescribed limits and accommodate coolant density changes throughout operation.

The RCS also serves as a boundary between the fission products and the environment. LRA Table 2.3.1-1 identifies thecomponents subject to an AMR for the RCS by component type and intended function.2.3.1.1.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has I appropriately identified the RCS mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an aging management review in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2-32* 2.3.3.13

  • 2.3.3.18
  • 2.3.3.21
  • 2.3.4.1
  • 2.3.4.2
  • 2.3.4.6 Hydrogen Monitoring System Miscellaneous Floor And Equipment Drains System Radwaste System* Condensate System Condensers And Air Removal System Main Generator And Auxiliary Systems 2.3.1 Reactor Vessel, Internals,and Reactor Coolant System LRA Section 2.3.1 describes the reactor vessel, internals, and reactor coolant system SCs subject to an AMR for license renewal. The applicant described the supporting SCs of the reactor vessel, internals, and reactor coolant system in the following LRA sections:
  • 2.3.1.1 Reactor coolant system
  • 2.3.1.2 Reactor vessel
  • 2.3.1.3 Reactor vessel internals
  • 2.3.1.4 Steam generator 2.3.1.1 Reactor Coo/ant System 2.3.1.1.1 Summary of Technical Information in the Application LRA Section 2.3.1.1 describes the reactor coolant system (RCS). The RCS is a normally operating system designed to circulate sub-cooled reactor coolant to transfer heat from the reactor vessel (RV) core to the secondary fluid in the once through steam generators (OTSGs). The RCS consists of RCS hot leg and cold leg piping, four reactor coolant pumps (RCPs), the pressurizer, pressurizer heaters, the pressurizer surge line, and the pressurizer spray line. The purpose of the RCS is to provide reactor coolant to the RV by either forced circulation from the RCPs or natural circulation, and to transfer the heat from the coolant to the secondary fluid 'in the OTSGs. The coolant from the RV exits through two hot leg fines and enters the OTSGs where the heat is transferred to the secondary fluid. The primary coolant then is pumped back into RV through the four cold legs by the four RCPs. The pressurizer and the pilot operated relief valve (PORV) and two pressurizer code safety valves maintain the RCS pressure within the prescribed limits and accommodate coolant density changes throughout operation.

The RCS also serVes as a boundary between the fission products and the environment. LRA Table 2.3.1-1 identifies the components subject to an AMR for the RCS by component type and intended function. . 2.3.1.1.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the. LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the RCS mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an aging management review in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2-32 2.3.1.2 Reactor Vessel 2.3.1.2.1 Summary Of Technical Information in the Application LRA Section 2.3.1.2 describes the reactor vessel (RV) system. The RV system is a normally operating system designed to contain the pressure and heat in the core and transfer this heat to the reactor coolant. The RV system consists of the reactor vessel, the control rod drive system, and reactor servicing equipment. The RV system also provides support for the reactor vessel internals, the core, and the control rod drive mechanisms. Four primary inlet nozzles receive coolant from the four cold legs from the RCS. The coolant then flows through the core and absorbs heat from the fuel and exits through the two outlet nozzles into the two hot legs of the RCS. The control rod drive system is used to insert negative reactivity into the reactor core. The RV also provides a pressure boundary for the fluid in the vessel and acts as a boundary to keep fission products from the environment. LRA Table 2.3.1-2 identifies the components subject to an AMR for the RV system by component type and intended function.2.3.1.2.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the RV system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.1.3 Reactor Vessel Internals 2.3.1.3.1 Summary Of Technical Information In The Application LRA Section 2.3.1.3 describes the RV internals system. The RV internals system is a normally operating system designed to generate heat in the core and transfer this heat to the reactor coolant. The RV internals system includes the fuel assemblies and the control rod assemblies. The plenum assembly and the core support assembly are major structural subassemblies of the RV internals system. These structural assemblies are used to maintain reactor core assembly geometry. The plenum assembly is a cylindrical assembly that is used to position the fuel and control rod assemblies, direct the flow out of the core, and provide resistance to hydraulic lift forces. The core support assembly is used to direct flow through the core and provides the structure to support the core. The core barrel assembly provides the area for the fuel assemblies to be loaded into and for coolant to flow upward through the fuel. The lower internals assembly provides for flow distribution and provides support and protection for core monitoring detectors. The 177 fuel assemblies are used to produce positive reactivity and provide heat for the reactor coolant to absorb. The 61 control rod assemblies are used to control the reactivity of the core and if need be shut down the reactor. LRA Table 2.3.1-3 identifies the components subject to aging management review for the reactor vessel internals by component type and intended function.2.3.1.3.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the reactor vessels internals system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately 2-33 2.3.1.2 Reactor Vessel 2.3.1.2.1 Summary Of Technical Information in the Application LRA Section 2.3.1.2 describes the reactor vessel (RV) system. The RV system is a normally operating system designed to contain the pressure and heat in the core and transfer this heat to the reactor coolant. The RV system consists of the reactor vessel, the control rod drive system, and reactor servicing equipment. The RV system also provides support for the reactor vessel internals, the core, and the control rod drive mechanisms. Four primary inlet nozzles receive coolant from the four cold legs from the RCS. The coolant then flows through the core and absorbs heat from the fuel and exits through the two outlet nozzles into the two hot legs of the RCS. The control rod drive system is used to insert negative reactivity into the reactor core. The RV also provides a pressure boundary for the fluid in the vessel and acts as a boundary to keep fission products from the environment. LRA Table 2.3.1-2 identifies the components subject to an AMR for the RV system by component type and intended function. 2.3.1.2.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the RV system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.1.3 Reactor Vessel Internals 2.3.1.3.1 Summary Of Technical Information In The Application LRA Section 2.3.1.3 describes the RV internals system. The RV internals system is a normally operating system designed to generate heat in the core and transfer this heat to the reactor coolant. The RV internals system includes the fuel assemblies and the control rod assemblies. The plenum assembly and the core support assembly are major structural subassemblies of the RV internals system. These structural assemblies are used to maintain reactor core assembly geometry. The plenum assembly is a cylindrical assembly that is used to position the fuel and control rod assemblies, direct the flow out of the core, and provide resistance to hydraulic lift forces. The core support assembly is used to direct flow through the core and provides the structure to support the core. The core barrel assembly provides the area for the fuel assemblies to be loaded into and for coolant to flow upward through the fuel. The lower internals assembly provides for flow distribution and provides support and protection for core monitoring detectors. The 177 fuel assemblies are used to produce positive reactivity and provide heat for the reactor coolant to absorb. The 61 control rod assemblies are used to control the reactivity of the core and if need be shut down the reactor. LRA Table 2.3.1-3 identifies the components subject to aging management review for the reactor vessel internals by component type and intended function. 2.3.1.3.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the reactor vessels internals system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately 2-33 identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.1.4 Steam Generators 2.3.1.4.1 Summary of Technical Information in the Application LRA Section 2.3.1.4 describes the steam generators. The steam generators are designed to act as a heat sink for the reactor coolant. The steam generators are once through tube and shell design. The reactor coolant flows through the tubes at the head and out the lower head while the secondary fluid flows through the shell from penetrations above the midpoint of the steam generators. The secondary fluid flows down through the annulus and then upward where it receives heat from the reactor coolant flow and boils into superheated steam and then exits the steam generator. The applicant stated that it will replace the original OTSGs with enhanced OTSGs before the period of extended operation. LRA Table 2.3.1-4 identifies the components subject to aging management review for the steam generators by component type and intended function.2.3.1.4.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the steam generator system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identifiedthe system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).

2.3.2 Engineered

Safety Features LRA Section 2.3.2, describes the engineered safety features system SCs subject to an AMR for license renewal. The applicant described the supporting SOs of the engineered safety features system in the following LRA sections:* Core flooding system* Decay heat removal system* Makeup and purification system (high pressure injection)

  • Primary containment heating and ventilation system* Reactor building spray system* Reactor building sump and drain system 2.3.2.1 Core Flooding System 2.3.2.1.1 Summary of Technical Information in the Application LRA Section 2.3.2.1 describes the core flooding system. The core flooding system is a passive system designed to automatically flood the core during intermediate and large reactor coolant system (RCS) pipe failures.

The core flooding system will automatically discharge borated water from two tanks directly into the RV if pressure drops under 600 psig. The core flooding system 2-34 identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.1.4 Steam Generators 2.3.1.4.1 Summary of Technical Information in the Application LRA Section 2.3.1.4 describes the steam generators. The steam generators are designed to act as a heat sink for the reactor coolant. The steam generators are once through tube and shell design. The reactor coolant flows through the tubes at the head and out the lower head while the secondary fluid flows through the shell from penetrations above the midpoint of the steam generators. The secondary fluid flows down through the annulus and then upward where it receives heat from the reactor coolant flow and boils into superheated steam and then exits the steam generator. The applicant stated that it will replace the original OTSGs with enhanced OTSGs before the period of extended operation. LRA Table 2.3.1-4 identifies the componepts subject to aging management review for the steam generators by component type and intehded function. 2.3.1.4.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the steam generator system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).

2.3.2 Engineered

Safety Features LRA Section 2.3.2, describes the engineered safety features system SCs subject to an AMR for license renewal. The applicant described the supporting SCs of the engineered safety features system in the following LRA sections:

  • Core flooding system
  • Decay heat removal system
  • Makeup and purification system (high pressure injection)
  • Primary containment heating and ventilation system
  • Reactor building spray system
  • Reactor building sump and drain system 2.3.2.1 Core Flooding System 2.3.2.1.1 Summary of Technical Information in the Application LRA Section 2.3.2.1 describes the core flooding system. The core flooding system is a passive system designed to automatically flood the core during intermediate and large reactor coolant system (RCS) pipe failures.

The core flooding system will automatically discharge borated water from two tanks directly into the RV if pressure drops under 600 psig. The core flooding system 2-34 consists of two tanks charged with nitrogen. These tanks are approximately two-thirds filled with borated water. During a transient, if the RCS pressure drops below the core flooding pressure of 600 psig, check valves will open and the borated water will be allowed to flow into the RV. This will cause a decrease in reactivity. Both tanks are required to re-cover the core in event of a loss of coolant accident (LOCA). LRA Table 2.3.2-1 identifies the components subject to an AMR for the core flooding system by component type and intended function.2.3.2.1.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the core flooding system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21 (a)(1).2.3.2.2 Decay Heat Removal System 2.3.2.2.1 Summary of Technical Information in the Application LRA Section 2.3.2.2 describes the decay heat removal system. The decay heat removal system removes decay heat from the core and residual heat from the RCS during the latter stages of cooldown. The system also provides auxiliary spray to the pressurizer for complete depressurization. The system can be used to inject borated water into the core following a LOCA by taking suction from the borated water storage tank and injecting it through the core flooding system. The system will also maintain the reactor coolant temperature below 140 'F during refueling. The decay heat removal system also provides an alternate way to fill and drain the fuel transfer canal. It can prevent boron precipitation after a LOCA through an auxiliary spray flow to the pressurizer. The decay heat removal system is designed so that a single failure will not prevent its functioning during a LOCA or loss of offsite power. LRA Table 2.3.2-2 identifies the components subject to an AMR for the decay heat removal system by component type and intended function.2.3.2.2.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the decay heat removal system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.2.3 Makeup and Purification System (High Pressure Injection) 2.3.2.3.1 Summary of Technical Information in the Application LRA Section 2.3.2.3 describes the makeup and purification system (MP). The MP consists of two systems: the plant makeup and purification system and the plant chemical addition system. The MP acts to control the inventory of the RCS during normal operation. The MP also has an emergency core cooling system (ECCS) function; it can be used to inject borated water at high pressure into the RV for emergency cooling during a LOCA. The chemical addition system allows 2-35 consists of two tanks charged with nitrogen. These tanks are approximately two-thirds filled with borated water. During a transient, if the RCS pressure drops below the core flooding pressure of 600 psig, check valves will open and the borated water will be allowed to flow into the RV. This will cause a decrease in reactivity. Both tanks are required to re-cover the core in event of a loss of coolant accident (LOCA). LRA Table 2.3.2-1 identifies the components subject to an AMR for the core flooding system by component type and intended function. 2.3.2.1.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has . appropriately identified the core flooding system mechanical components within the scope of license renewal, as required by 10 CFR 54.4{a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.2.2 Decay Heat Removal System 2.3.2.2.1 Summary of Technical Information in the Application LRA Section 2.3.2.2 describes the decay heat removal system. The decay heat removal system removes decay heat from the core and residual heat from the RCS during the latter stages of cooldown. The system also provides auxiliary spray to the pressurizer for complete depressurization. The system can be used to inject borated water into the core following a LOCA by taking suction from the borated water storage tank and injecting it through the core flooding system. The system will also maintain the reactor coolant temperature below 140 of during refueling. The decay heat removal system also provides an alternate way to fill and drain the fuel transfer canal. It can prevent boron precipitation after a LOCA through an auxiliary spray flow to the pressurizer. The decay heat removal system is designed so that a single failure will not prevent its functioning during a LOCA or loss of offsite power. LRA Table 2.3.2-2 identifies the components subject to an AMR for the decay heat removal system by component type and intended function. 2;3.2.2.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the decay heat removal system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.2.3 Makeup and Purification System (High Pressure Injection) 2.3.2.3.1 Summary of Technical Information in the Application LRA Section 2.3.2.3 describes the makeup and purification system (MP). The MP consists of two systems: the plant makeup and purification system and the plant chemical addition system. The MP acts to control the inventory of the RCS during normal operation. The MP also has an emergency core cooling system (ECCS) function; it can be used to inject borated water at high pressure into the RV for emergency cooling during a LOCA. The chemical addition system allows 2-35 for chemistry related functions in the RCS, the spent fuel cooling system, and the radwaste system. The chemical addition system provides boric acid to primary reactor coolant and the borated water storage tank as well as providing chemical and pH control to various other systems.LRA Table 2.3.2-3 identifies the components subject to an AMR for the MP by component type and intended function.2.3.2.3.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the makeup and purification system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.2.4 Primary Containment Heating and Ventilation System 2.3.2.4.1 Summary of Technical Information in the Application LRA Section 2.3.2.4 describes the primary containment heating and ventilation system (PCHV).The PCHV consists of the following plant systems: (a) Penetrations Air Cooling System (b) Reactor Building Emergency Cooling Water (c) Reactor Building Cooling System (d) Reactor Building Miscellaneous Heating and Ventilation Systems The penetrations air cooling system is a normally operating, mechanical system designed to cool the containment penetrations. The system accomplishes this by supplying filtered, cooled air from the outside or from the turbine hall to the penetrations. The reactor building emergency cooling water system is designed to limit post accident containment pressure and temperature. The system accomplishes this by providing cooling water to the reactor building air handling units via the reactor building emergency cooling coils. The system is normally in emergency standby mode.The reactor building cooling system is designed to remove sensible and latent heat from the reactor building during normal and emergency conditions to maintain the building temperature with the range of design temperatures. The system accomplishes this by supplying filtered, cooled air to the reactor building. The system is normally in operation.The reactor building miscellaneous heating and ventilation systems is designed to heat and cool locations around the reactor building and accomplishes this by supplying filtered, tempered air throughout the reactor building.LRA Table 2.3.2-4 identifies the components subject to an AMR for the PCHV system by component type and intended function.2-36 for chemistry related functions in the RCS, the spent fuel cooling system, and the radwaste system. The chemical addition system provides boric acid to primary reactor coolant and the borated water storage tank as well as providing chemical and pH control to various other systems. LRA Table 2.3.2-3 identifies the components subject to an AMR for the MP by component type and intended function. 2.3.2.3.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 'LRA, UFSAR, and applicable boundary drawings, the staff con.cludes that the applicant has appropriately identified the makeup and purification system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.2.4 Primary Containment Heating and Ventilation System 2.3.2.4.1 Summary of Technical Information in the Application LRA Section 2.3.2.4 describes the primary containment heating and ventilation system (PCHV). The PCHV consists of the following plant systems: (a) Penetrations Air Cooling System (b) Reactor Building Emergency Cooling Water (c) Reactor Building Cooling System (d) Reactor Building Miscellaneous Heating and Ventilation Systems The penetrations air cooling system is a normally operating, mechanical system designed to cool the containment penetrations. The system accomplishes this by supplying filtered, cooled air from the outside or from the turbine hall to the penetrations. The reactor building emergency cooling water system is designed to limit post accident containment pressure and temperature. The system accomplishes this by providing cooling water to the reactor building air handling units via the reactor building emergency cooling coils. The system is normally in emergency standby mode. The reactor building cooling system is designed to remove sensible and latent heat from the reactor building during normal and emergency conditions to maintain the building temperature with the range of design temperatures. The system accomplishes this by supplying filtered, cooled air to the reactor building. The system is normally in operation. The reactor building miscellaneous heating and ventilation systems is designed to heat and cool locations around the reactor building and accomplishes this by supplying filtered, tempered air throughout the reactor building. LRA Table 2.3.2-4 identifies the components subject to an AMR for the PCHV system by component type and intended function. 2-36 2.3.2.4.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the primary containment heating and ventilation system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.2.5 Reactor Building Spray System 2.3.2.5.1 Summary of Technical Information in the Application LRA Section 2.3.2.5 describes the reactor building spray system as a mechanical, standby, two redundant train system designed to reduce reactor building pressure to nearly atmospheric pressure, to remove airborne fission products from the reactor building atmosphere and to minimize corrosion of equipment following a LOCA. The reactor building spray system is in scope for license renewal and has interfaces with other systems that are not in the license renewal boundary of the reactor building spray system.The reactor building spray system removes energy from the environment by transferring heat from the higher temperature atmosphere to the lower temperature spray droplets. These droplets are discharged from spray nozzles that are arranged on two concentric spray headers located on the inside dome of the reactor building. Trisodium phosphate (TSP), added to the reactor building spray system, is used to remove airborne fission products from the reactor building atmosphere. The TSP baskets which hold the TSP are included in the scope of the reactor building license renewal system. LRA Table 2.3.2-5 identifies the components subject to aging management review for the reactor building spray system by component type and intended function.2.3.2.5.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the reactor building spray system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.2.6 Reactor Building Sump and Drain System 2.3.2.6.1 Summary of Technical Information in the Application LRA Section 2.3.2.6 describes the reactor building sump & drain system. The reactor building sump & drain system is a passive, mechanical, system designed to collect leakage within the reactor building during normal operations and during emergency events. The reactor building sump and drain system consists of the reactor building sump, decay heat removal strainer, piping, valves and supporting instrumentation. The reactor building sump collects and stores leakage and condensation from equipment, floor drains, the liquid discharged from the reactor building spray system and the reactor coolant lost during a LOCA. Equipment that drains to the reactor building sump includes: the reactor coolant 2-37 2.3.2.4.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the primary containment heating and ventilation system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.2.5 Reactor Building Spray System 2.3.2.5.1 Summary of Technical Information in the Application LRA Section 2.3.2.5 describes the reactor building spray system as a mechanical, standby, two redundant train system designed to reduce reactor building pressure to nearly atmospheric pressure, to remove airborne fission products from the reactor building atmosphere and to minimize corrosion of equipment following a LOCA. The reactor building spray system is in scope for license renewal and has interfaces with other systems that are not in the license renewal boundary of the reactor building spray system. The reactor building spray system removes energy from the environment by transferring heat from the higher temperature atmosphere to the lower temperature spray droplets. These droplets are discharged from spray nozzles that are arranged on two concentric spray headers located on the inside dome of the reactor building. Trisodium phosphate (TSP), added to the reactor building spray system. is used to remove airborne fission products from the reactor building atmosphere. The TSP baskets which hold the TSP are included in the scope of the reactor building license renewal system. LRA Table 2.3.2-5 identifies the components subject to aging management review for the reactor building spray system by component type and intended function. 2.3.2.5.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the reactor building spray system mechanical components within the scope of license renewal, as required by 10CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.2.6 Reactor Building Sump and Drain System 2.3.2.6.1 Summary of Technical Information in the Application LRA Section 2.3.2.6 describes the reactor building sump & drain system. The reactor building sump & drain system is a passive, mechanical, system designed to collect leakage within the reactor building during normal operations and during emergency events. The reactor building sump and drain system consists of the reactor building sump, decay heat removal strainer, piping, valves and supporting instrumentation. The reactor building sump collects and stores leakage and condensation from equipment, floor drains, the liquid discharged from the reactor building spray system and the reactor coolant lost . during a LOCA. Equipment that drains to the reactor building sump includes: the reactor coolant 2-37 pump mechanical seals, the makeup & purification letdown coolers and the reactor building'coolers.The reactor building sump & drain system is in scope for license renewal. The reactor building sump & drain system also has several interfaces with other systems that are not in the license renewal boundary of the reactor building sump and drain system. LRA Table 2.3.2-6 identifies the components subject to an AMR for the reactor building sump and drain system by component type and intended function.2.3.2.6.2 ConclusionThe staff followed the evaluation methodology discussed in Section 2.3 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such, omissions. On the basis of its review, the staff concludes that the applicant has adequately 1 identified the reactor building sump and drain system 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).

2.3.3 Auxiliary

Systems LRASection-2.3.3,-describes the-auxiliarysystemSCs subject to an AMR for license renewal.The applicant described the supporting SCs of the auxiliary systems in the following LRA sections: " Auxiliary and fuel handling building ventilation system* Auxiliary steam system* Circulating water system* Closed cycle cooling water system 1 Containment isolation system* Control building ventilation system* Cranes and hoists* Diesel generator building ventilation system* Emergency diesel generators and auxiliary systems* Fire protection system* Fuel handling and fuel storage system* Fuel oil system* Hydrogen monitoring system* Instrument and control air system* Intake screen and pump house ventilation system" Intermediate building ventilation system* Liquid and gas sampling system* Miscellaneous floor and equipment drains system* Open cycle cooling water system* Radiation monitoring system* Radwaste system* Service building chilled water system* Spent fuel cooling system 2-38 pump mechanical seals, the makeup & purification letdown coolers and the reactor building coolers. The reactor building sump & drain system is in scope for license renewal. The reactor buildi,ng sump & drain system also has several interfaces with other systems that are not in the license renewal boundary of the reactor building sump and drain system. LRA Table 2.3.2-6 identifies the components subject to an AMR for the reactor building sump and drain system by component type and intended function. 2.3.2.6.2 Conclusion The staff followed the evaluation methodology discussed in Section 2.3 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such ,: omissions. On the basis of its review, the staff concludes that the applicant has identified the reactor building sump and drain system SCs within the scope of license renewal, as required by 10CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3 Auxiliary

Systems . : ------------LRASectiol'l-2.3.3,-descrihes-the.auxiliary_system_S.Cs subject to an AMR for license renewal. The applicant described the supporting SCs of the auxiliary systems in the following LRA sections:

  • Auxiliary and fuel handling building ventilation system
  • Auxiliary steam system
  • Circulating water system
  • Closed cycle cooling water system
  • Containment isolation system
  • Control building ventilation system
  • Cranes and hoists
  • Diesel generator building ventilation system
  • Emergency diesel generators and auxiliary systems
  • Fire protection system
  • Fuel handling and fuel storage system
  • Fuel oil system
  • Hydrogen monitoring system
  • Instrument and control air system
  • Intake screen and pump house ventilation system
  • Intermediate building ventilation system
  • Liquid and gas sampling system
  • Miscellaneous floor and equipment drains system
  • Open cycle cooling water system
  • Radiation monitoring system
  • Radwaste system
  • Service building chilled water system
  • Spent fuel cooling system 2-38

" Station blackout and UPS diesel generator system* Water treatment and distribution system 2.3.3.1 Auxiliary and Fuel Handling Building Ventilation System 2.3.3.1.1 Summary of Technical Information in the Application LRA Section 2.3.3.1 describes the auxiliary and fuel handling building ventilation (AFBV) systems which consist of the (1) auxiliary and fuel handling buildings heating and ventilation system, (2)nuclear services closed cooling water (NSCCW) pumps and decay heat (DH) pumps cooling system, (3) spent fuel cooling pumps cooling system, and (4) fuel handling building engineered safety features ventilation system (FHBESFVS). The AFBV except for the FHBESFVS is in service during normal plant operation. The FHBESFVS is placed into operation prior to any movement of irradiated fuel within the fuel handling building.The purpose of the AFBV is to provide filtered tempered air for ventilation to the auxiliary and fuelhandling buildings, maintain a negative pressure relative to the outside environment, cool selected areas where heat generation is unusually high, and to control radioactive material released in the exhaust air.The AFBV System supplies outside air via fans through electric heaters to the auxiliary and fuelhandling buildings. It supplies cooled air via fans and air coolers to the areas where heat generation is unusually high. Exhaust air is filtered by the system prior to release.LRA Table 2.3.3-1 identifies the components subject to an AMR for the auxiliary and fuel handling building ventilation system by component type and intended function.2.3.3.1.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the AFBV system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified thesystem components subject to an aging management review in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.2 Auxiliary Steam System 2.3.3.2.1 Summary of Technical Information in the Application LRA Section 2.3.3.2 describes the auxiliary steam (AS) system which consists of the following plant systems: auxiliary steam, auxiliary boilers, and auxiliary boiler chemical addition systems.The purpose of the AS system is to provide steam to the main feedwater pump turbines, turbine gland seals, and feedwater heaters during startup, and to supply steam to the emergency feedwater pump turbine during shutdown, if required. It also distributes steam to heat components during all plant conditions, as required. The AS system accomplishes this by distributing steam to the supplied systems from the main steam system or the extraction steam system, when available. The AS system also provides part of the main condenser vacuum boundary, through the heating loop in the auxiliary steam boilers. LRA Table 2.3.3-2 identifies the components subject to an AMR for the auxiliary steam system by component type and intended function.2-39* Station blackout and UPS diesel generator system

  • Water treatment and distribution system 2.3.3.1 Auxiliary and Fuel Handling Building Ventilation System 2.3.3.1.1 Summary of Technical Information in the Application LRA Section 2.3.3.1 describes the auxiliary and fuel handling building ventilation (AFBV) systems which consist of the(1) auxiliary and fuel handling buildings heating and ventilation system, (2) nuclear services closed cooling water (NSCCW) pumps and decay heat (OH) pumps cooling system, (3) spent fuel cooling pumps cooling system, and (4) fuel handling building engineered safety features ventilation system (FHBESFVS).

The AFBV except for the FHBESFVS is in service during normal plant operation. The FHBESFVS is placed into operation prior to any movement of irradiated fuel within the fuel handling building. The purpose of the AFBV is to provide filtered tempered air for ventilation to the auxiliary and fuel handling buildings, maintain a negative pressure relative to the outside environment, cool selected areas where heat generation is unusually high, and to control radioactive material . released in the exhaust air. The AFBV System supplies outside air via fans through electric heaters to the auxiliary and fuel handling buildings. It supplies cooled air via fans and air coolers to the areas where heat generation is unusually high. Exhaust air is filtered by the system prior to release. LRA Table 2.3.3-1 identifies the components subject to an AMR for the auxiliary and fuel handling building ventilation system by component type and intended function. 2.3.3.1.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the AFBV system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an aging management review in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.2 Auxiliary Steam System 2.3.3.2.1 Summary of Technical Information in the Application LRA Section 2.3.3.2 describes the auxiliary steam (AS) system which consists of the following plant systems: auxiliary steam, auxiliary boilers, and auxiliary boiler chemical addition systems. The purpose of the AS system is to provide steam to the main feedwater pump turbines, turbine gland seals, and feedwater heaters during startup, and to supply steam to the emergency feedwater pump turbine during shutdown, if required. It also distributes steam to heat components during all plant conditions, as required. The AS system accomplishes this by distributing steam to the supplied systems from the main steam system or the extraction steam system, when available .. The AS system also provides part of the main condenser vacuum boundary, through the heating loop in the auxiliary steam boilers. LRA Table 2.3.3-2 identifies the components subject to an AMR for the auxiliary steam system by component type and intended function. 2-39 2.3.3.2.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of theiý LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the AS system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21 (a)(1).2.3.3.3 Circulating Water System 2.3.3.3.1 Summary of Technical Information in the Application LRA Section 2.3.3.3 describes the circulating water (CW) system which consists of the following plant systems: mechanical components of the natural draft cooling towers (NDCTs), CW system, condenser amertap system, and CW biocide system. The CW system is a mechanical system designed to provide cooling water to the main condensers, auxiliary condensers and main and auxiliary vacuum pumps under normal operation. The CW system accomplishes this by circulating river water through the main and auxiliary condensers, and through the main and auxiliary condenser air removal system to absorb process heat which is then rejected through the two natural draft cooling towers. The system also includes a chemical injection system for the addition of chemicals that control biological growth in the system and other chemical parameters. The CW system is normally in operation and is manually controlled. LRA Table 2.3.3-3 identifies the components subject to an AMR for the circulating water system by component type and intended function.2.3.3.3.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concludes there is reasonable assurance that the applicant has appropriately identified the CW system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.4 Closed Cycle Cooling Water System 2.3.3.4.1 Summary of Technical Information in the Application LRA Section 2.3.3.4 describes the closed cycle cooling water (CCCW) system which consists of the following plant systems: nuclear services closed cooling water system, intermediate closed cooling water system, decay heat closed cooling water system, secondary services closed coolingwater system, industrial cooler system, and chemical feed for industrial coolers system. The CCCW system is an auxiliary system designed to provide intermediate loop cooling for nuclearand non-nuclear plant loads.The CCCW system is designed to provide cooling water to both safety related and nonsafety-related components. The CCCW system accomplishes this by circulating closed cooling waterthrough the nuclear services heat exchangers, intermediate coolers, decay heat service coolers, 2-40 2.3.3.2.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of thel LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the AS system mechanical components within the scope of license *. renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.3 . Circulating Water System 2.3.3.3.1 Summary of Technical Information in the Application LRA Section 2.3.3.3 describes the circulating water (CW) system which consists of the following plant systems: mechanical components of the natural draft cooling towers (NDCTs), CW system, condenser amertap system, and CW biocide system. The CW system isa mechanical system designed to provide cooling water to the main condensers, auxiliary condensers and main and auxiliary vacuum pumps under normal operation. The CW system accomplishes this by circulating river water through the main and auxiliary condensers, and through the main and auxiliary condenser air removal system to absorb process heat which is then rejected through the two natural draft cooling towers. The system also includes a chemical injection system for the addition of chemicals that control biological growth in the system and other chemical parameters. The CW system is normally in operation and is manually controlled. LRA Table 2.3.3-3 identifies the components subject to an AMRfor the circulating water system by component type and intended function. 2.3.3.3.2 Conclusion Based on. the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concludes there is reasonable assurance that the applicant has appropriately identified the OW system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components*subject to an AMR in accordance with the requirements stated in 10 CFR 54.21 (a)(1). 2.3.3.4 Closed Cycle Cooling Water System 2.3.3.4.1 Summary of Technical Information in the Application LRA Section 2.3.304 describes the closed cycle cooling water (CCCW) system which consists of the following plant systems: nuclear services closed cooling water system, intermediate closed cooling water system, decay heat closed cooling water system, secondary services closed cooling water system, industrial cooler system, and chemical feed for industrial coolers system. The CCCW system is an auxiliary system designed to provide intermediate loop cooling for nuclear and non-nuclear plant loads. . The CCCW system is designed to provide cooling water to both safety related and related components. The CCCW system accomplishes this by circulating closed cooling water through the nuclear services heat intermediate coolers, decay heat service coolers, 2-40 decay heat removal coolers, secondary services heat exchangers, and industrial coolers and other safety-related and nonsafety-related plant heat exchangers and coolers. LRA Table 2.3.3-4 identifies the components subject to an AMR for the CCCW System by component type and intended function.2.3.3.4.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.4 and UFSAR Sections 9.6.2.3, 9.3, 9.6.2.5, 9.6.2.2, 9.9.4.1.d, and 5.6.4 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions 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 the applicant has not 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 2.3.3.4 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results.In RAI 2.3.3.4-1, dated August 20, 2008, the staff noted that on license renewal drawing LR-302-175, five components, which appear to be sight flow indicators according to license renewal drawing LR-302-002, are highlighted in red, indicating these components are within scope for license renewal under 10 CFR 54.4(a)(2). Typically, this component type has a leakage boundary function. Sight flow indicators are not listed in LRA Tables 2.3.3-4 and 3.3.2-4 as a component type with a leakage boundary function. The staff requested that the applicant provide additional information to justify the exclusion of the sight flow indicators from LRA Tables 2.3.3-4 and 3.3.2-4.In its response to the RAI, dated September 16, 2008, the applicant stated that the sight flow indicators (sight glasses), shown in red on license renewal drawing LR-302-175, are within the scope of license renewal with an intended function of leakage boundary; however, they were inadvertently omitted from LRA Tables 2.3.3-4 and 3.3.2-4. Also in its response, the applicant amended the LRA by adding the component sight glasses with an intended function of leakage boundary to LRA Table 2.3.3-4, adding the material glass to LRA Section 3.3.2.1.4, and adding component type sight glasses to LRA Table 3.3.2-4 with complete AMR results.Based on its review, the staff finds the applicant's response to RAI 2.3.3.4-1 acceptable, because the applicant added "sight glasses" with an intended function of leakage boundary to LRA Tables 2.3.3-4 and 3.3.2-4, and added the material "glass" to LRA Section 3.3.2.1.4. The staffs concern described in RAI 2.3.3.4-1 is resolved.In RAI 2.3.3.4-2, dated August 20, 2008, the staff noted that the following coolers are highlighted on their respective license renewal drawings as being within scope for license renewal; however, these coolers are not specifically listed in LRA Tables 2.3.3-4 and 3.3.2-4 as being subject to an AMR: 2-41 decay heat removal coolers, secondary services heat exchangers, and industrial coolers and other safety-related and nonsafety-related plant heat exchangers and coolers. LRA Table 2.3.3-4 identifies the components subject to an AMR for the CCCW System by component type and intended function. 2.3.3.4.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.4 and UFSAR Sections 9.6.2.3, 9.3, 9.6.2.5, 9.6.2.2, 9.9.4.1.d, and 5.6.4 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions 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 the applicant has not omitted any passive and long-lived components subject to an AMR, in accordance with 10 CFR 54.21(a)(1). The staff's review of LRA Section 2.3.3.4 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. In RAI 2.3.3.4-1, dated August 20,2008, the staff noted that on license renewal drawing LR-302-175, five components, which appear to be sight flow indicators according to license renewal drawing LR-302-002, are highlighted in red, indicating these components are within scope for license renewal under 10 CFR 54.4(a)(2). Typically, this component type has a leakage boundary function. Sight flow indicators are not listed in LRA Tables 2.3.3-4 and 3.3.2-4 as a component type with a leakage boundary function. The staff requested that the applicant provide additional information to justify the exclusion of the sight flow indicators from LRA Tables 2.3.3-4 and 3.3.2-4. In its response to the RAI, dated September 16, 2008, the applicant stated that the Sight flow indicators (sight glasses), shown in red on license renewal drawing LR-302-175, are within the scope of license renewal with an intended function of leakage boundary; however, they were inadvertently omitted from LRA Tables and 3.3.2-4. Also in its response, the applicant amended the LRA by adding the component sight glasses with an intended function of leakage boundary to LRA Table 2.3.3-4, adding the material glass to LRA Section 3.3.2.1.4, and adding component type sight glasses to LRA Table 3.3.2-4 with complete AMR results. Based on its review, the staff finds the applicant's response to RAI2.3.3.4-1 acceptable, because the applicant added "sight glasses" with an intended function of leakage boundary to LRA Tables 2.3.3-4 and 3.3.2-4, and added the material "glass" to LRA Section 3.3.2.1.4. The staff's concern described in RAI 2.3.3.4-1 is resolved. In RAI 2.3.3.4-2, dated August 20, 2008, the staff noted that the following coolers are highlighted on their respective license renewal drawings as being within scope for license renewal; however, these coolers are not specifically listed in LRA Tables 2.3.3-4 and 3.3.2-4 as being subject to an AMR: 2-41 " Closed cycle cooling water system, intermediate coolers (IC-C-IA and IC-C-IB) on license renewal drawing LR-302-620, also on LR-302-202

  • Reactor coolant pump thermal barrier heat exchangers (1A, 1 B, 1C, and 1D) on license renewal drawing LR-302-620
  • Makeup and purification system shown on license renewal drawing LR-302-662 and LR-302-645 (typically for the three makeup pumps MU-P-1A/B/C)" Pump and motor lube oil coolers (MU-C-3A/B/C)" Motor air coolers (MU-C-4A/B/C)
  • Gear unit oil coolers (MU C 5A/B/C)* Decay heat removal pumps' (DH P 1A and DH-P-1B) motor coolers, and bearing coolers, on license renewal drawing LR-302-645
  • Temperature control unit (SS-C-46) on license renewal drawing LR-302-181" Isolated phase bus duct coolers (SC-C-3A and SC-C-3B) on license renewal drawing LR-302-221 The staff requested that the applicant provide additional information to justify the exclusion of the above mentioned coolers from LRA Tables 2.3.3-4 and 3.3.2-4.In its response to the RAI, dated September 16, 2008, the applicant stated that all the components listed the RAI 2.3.3.4-2 are within the scope of license renewal as follows: The applicant explained that the CCCW intermediate coolers are within the scope of license renewal with a heat transfer intended function.

Both sides of the heat transfer surfaces have been evaluated for license renewal under the open cycle cooling water (OCCW) system. These components are already included in LRA Tables 2.3.3-19 and 3.3.2-19 with the OCCW system and shown on license renewal drawing LR-302-202. The applicant stated that the reactor coolant pump thermal barrier heat exchangers should !!have been included in LRA Tables 2.3.3-4 and 3.3.2-4 as component type "heat exchanger components (Reactor Coolant Pump Thermal Barrier)." The applicant amended the LRA by adding the component heat exchanger components (Reactor Coolant Pump Thermal Barrier) with an intended function of pressure boundary to LRA Table 2.3.3-4, and added the same component name to LRA Table 3.3.2-4 with complete AMR results.For the remaining components described in RAI 2.3.3.4-2, the applicant stated that they should have included these components in LRA Tables 2.3.3-4 and 3.3.2-4. The applicant explained that these components should have been grouped with coolers of similar design already shown! in LRA Tables 2.3.3-4 and 3.3.2-4. The applicant amended the LRA by adding the remaining components listed in the RAI to the groupings of coolers of similar design already shown or by adding new components in LRA Tables 2.3.3-4 and 3.3.2-4.The applicant amended the LRA by adding additional AMR results for new material, environment, and aging effect combinations associated with the existing component types piping and fittings and valve body for the CCCW system.2-42* Closed cycle cooling water system, intermediate coolers (IC-C-1A and IC-C-1 B) on license renewal drawing LR-302-620, also on LR-302-202

  • Reactor coolant pump thermal barrier heat exchangers (1 A, 1 B, 1 C, and 1 D) on license renewal drawing LR-302-620
  • Makeup and purification system shown on license renewal drawing LR-302-662 and LR-302-645 (typically for the three makeup pumps MU-P-1A1B/C)
  • Pump and motor lube oil coolers (MU-C-3A1B/C)
  • Motor air coolers (MU-C-4A1B/C)
  • Gear unit oil coolers (MU C 5A1B/C)
  • Decay heat removal pumps' (DH P 1A and DH-P-1 B) motor coolers, and bearing coolers, on license renewal drawing LR-302-645
  • Temperature control unit (SS-C-46) on license renewal drawing LR-302-181
  • Isolated phase bus duct coolers (SC-C-3A and SC-C-3B) on license renewal drawing LR-302-221 The staff requested that the applicant provide additional information to justify the exclusion of the . above mentioned coolers from LRA Tables 2.3.3-4 and 3.3.2-4. In its response to the RAI, dated September 16,2008, the applicant stated that all the components listed the RAI 2.3.3.4-2 are within the scope of license renewal as follows: The applicant explained that the CCCW intermediate coolers are within the scope of license renewal with a heat transfer intended function.

Both sides of the heat transfer surfaces have been " evaluated for license renewal under the open cycle cooling water (OCCW) system. These . components are already included in LRA Tables 2.3.3-19 and 3.3.2-19 with the OCCW system and shown on license renewal drawing LR-302-202. The applicant stated that the reactor coolant pump thermal barrier heat exchangers should ;!have been included in LRA Tables 2.3.3-4 and 3.3.2-4 as component type "heat exchanger components (Reactor Coolant Pump Thermal Barrier)." The applicant amended the LRA by adding the component heat exchanger components (Reactor Coolant Pump Thermal Barrier) with an intended function of pressure boundary to LRA Table 2.3.3-4, and added the same component name to LRA Table 3.3.2-4 with complete AMR results. I For the remaining components described in RAI 2.3.3.4-2, the applicant stated that they should have included these components in LRA Tables 2.3.3-4 and 3.3.2-4. The applicant that these components should have been grouped with coolers of similar design already shown!' in LRA Tables 2.3.3-4 and 3.3.2-4. The applicant amended the LRA by adding the remaining components listed in the RAI to the groupings of coolers of similar design already shown or by adding new components in LRA Tables 2.3.3-4 and 3.3.2-4. The applicant amended the LRA by adding additional AMR results for new material, environment, and aging effect combinations associated with the existing component types piping and fittings and valve body for the CCCW system. 2-42 Based on its review, the staff finds the applicant's response to RAI 2.3.3.4-2 acceptable because the applicant identified the location in the LRA of the AMR for the intermediate coolers and added all the components listed in the RAI, except intermediate coolers, with intended functions of leakage boundary, pressure boundary, or heat transfer to LRA Tables 2.3.3-4 and 3.3.2-4. The staff's concern described in RAI 2.3.3.4-2 is resolved.2.3.3.4.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the CCCW system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.5 Containment Isolation System 2.3.3.5.1 Summary of Technical Information in the Application LRA Section 2.3.3.5 describes the containment isolation (Cl) system which is comprised of the plant systems that are in scope for license renewal only to perform primary containment isolation. The Cl system consists of: (1) penetration pressurization system, (2) reactor building isolation system, (3) containment leak rate testing, (4) steam generator chemical cleaning system, (5)reactor building purge & kidney system, (6) nuclear plant nitrogen supply, (7) post-LOCA hydrogen recombiner system, and (8) hydrogen purge discharge system.The purpose of the Cl system is to provide containment isolation which is accomplished by providing a double barrier so that no single, credible failure or malfunction of an active component can result in intolerable leakage or loss of isolation. The installed double barriers include piping systems and isolation valves. LRA Table 2.3.3-5 identifies the components subject to an AMR for the containment isolation system by component type and intended function.2.3.3.5.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the Cl system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21 (a)(1).2.3.3.6 Control Building Ventilation System 2.3.3.6.1 Summary of Technical Information in the Application In LRA Section 2.3.3.6, the applicant discussed the control building ventilation (CBV) system which consists of the following plant systems: (1) control building & machine shop heating and ventilation (CBMSHV) system, (2) control building chilled water system, (3) control building compressed air system, and the (4) air intake tunnel (non-structural) system. The CBV system ventilation runs continuously. 2-43 Based on its review, the staff finds the applicant's response to RAI 2.3.3.4-2 acceptable because the applicant identified the location in the LRA of the AMR for the intermediate coolers and added all the components listed in the RAI, except intermediate coolers, with intended functions of leakage boundary, pressure boundary, or heat transfer to LRA Tables 2.3.3-4 and 3.3.2-4. The staff's concern described in RAI 2.3.3.4-2 is resolved. 2.3.3.4.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the CCCW system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21 (a)( 1 ). 2.3.3.5 Containment Isolation System 2.3.3.5.1 Summary of Technical Information in the Application LRA Section 2.3.3.5 describes the containment isolation (CI) system which is comprised of the plant systems that are in scope for license renewal only to perform primary containment isolation. The CI system consists of: (1) penetration pressurization system, (2) reactor building isolation system, (3) containment leak rate testing, (4) steam generator chemical cleaning system, (5) reactor buildil'Jg purge & kidney system, (6) nuclear plant nitrogen supply, (7) post-LOCA hydrogen recombiner system, and (8) hydrogen purge discharge system. The purpose of the CI system is to provide containment isolation which is accomplished by providing a double barrier so that no single, credible failure or malfunction of an active component can result in intolerable leakage or loss of isolation. The installed double barriers include piping systems and isolation valves. LRA Table 2.3.3-5 identifies the components subject to an AMR for the containment isolation system by component type and intended function. 2.3.3.5.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the CI system mechanical components within the scope of license renewal, as required by 1 OCFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.6 Control Building Ventilation System 2.3.3.6.1 Summary of Technical Information in the Application In LRA Section 2.3.3.6, the applicant discussed the control building ventilation (CBV) system which consists of the following plant systems: (1) control building & machine shop heating and ventilation (CBMSHV) system, (2) control building chilled water system, (3) control building compressed air system, and the (4) air intake tunnel (non-structural) system. The CBV system ventilation runs continuously. 2-43 The purpose of the CBV system is to provide filtered, tempered air to both safety-related and nonsafety-related areas of the control building by supplying both outside air from the air intake tunnel and recirculated air to rooms and areas within the control building.During normal operation, the CBV system supplies a mixture of outside air and recirculated air to the control building. If one or more of the hazards in the outside air intake tunnel, such as smoke or combustible gasses, is detected or an abnormally high radiation level in the control room is detected following the occurrence of a design basis accident in the reactor building that results in an engineered safeguard signal, the system is automatically placed into emergency recirculation mode.The control building chilled water system is normally in operation and supplies cooling for the CBV System ventilation coolers and the penetration air coolers. Also included in the CBV system is a dedicated compressed gas system, which provides control air and maintains necessary air pressure to operate chilled water valves and CBV air operated dampers.LRA Table 2.3.3-6 identifies the components subject to an AMR for the CBV system by component type and intended function.2.3.3.6.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the CBV system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.7 Cranes and Hoists 2.3.3.7.1 Summary of Technical Information in the Application LRA Section 2.3.3.7 describes the cranes and hoists (CH) system which consists of cranes and material handling equipment, turbine building crane, reactor building polar crane, fuel handling building crane, and river pump service crane bridge. The purpose of the CH System is to safely move material and equipment as required to support operations and maintenance activities. The CH system is comprised of load handling overhead bridge cranes, monorails, jib cranes, lifting devices, and hoists provided throughout the facility to support operation and maintenance activities. Major cranes include the reactor building polar crane, fuel handling building crane, and river pump service bridge crane.The reactor building polar crane services the operating floor and is used to lift all heavy loads such as the reactor closure head. The fuel handling building crane is used to handle new and spent fuel. The river pump service bridge crane services the river water pumps in the intake screen and pump house.LRA Table 2.3.3-7 identifies the components subject to an AMR for the CH System by component type and intended function.2-44 The purpose of the CBV system is to provide filtered, tempered air to both safety-related and nonsafety-related areas of the control building by supplying both outside air from the air intake tunnel and recirculated air to rooms and areas within the control building. During operation, the CBV system a mixture. of air and recirculated:1air to . the control bUilding. If one or more of the hazards In the outside air Intake tunnel, such as smoke or combustible gasses, is detected or an abnormally high radiation level in the control room is detected following the occurrence of a design basis accident in the reactor building that results in an engineered safeguard signal, the system is automatically placed into emergency recirculation mode. The control building chilled water system is normally in operation and supplies cooling for the CBV System ventilation coolers and the penetration air coolers. Also included in the CBV system is a dedicated compressed gas system, which provides control air and maintains necessary air pressure to operate chilled water valves and CBV air operated dampers. LRA Table 2.3.3-6 identifies the components subject to an AMR for the CBV system by component type and intended function. 2.3.3.6.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the CBV system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21 (a)(1). 2.3.3.7 Cranes and Hoists 2.3.3.7.1 Summary of Technical Information in the Application LRA Section 2.3.3.7 describes the cranes and hoists (CH) system which consists of cranes and material handling equipment, turbine building crane, reactor building polar crane, fuel handling building crane, and river pump service crane bridge. The purpose of the CH System is to safely move material and equipment as required to support operations and maintenance activities. The CH system is comprised of load handling overhead bridge cranes, monorails, jib cranes, lifting devices, and hoists provided throughout the facility to support operation and maintenance activities. Major cranes include the reactor building polar crane, fuel handling building crane, and river pump service bridge crane. The reactor building polar crane services the operating floor and is used to lift all heavy loads such as the reactor closure head. The fuel handling building crane is used to handle new and spent fuel. The river pump service bridge crane services the river water pumps in the intake screen and pump house. LRA Table 2.3.3-7 identifies the components subject to an AMR for the CH System by component type and intended function. 2-44 2.3.3.7.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concludes there is reasonable assurance that the applicant has appropriately identified the CH system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21 (a)(1).2.3.3.8 Diesel Generator Building Ventilation System 2.3.3.8.1 Summary of Technical Information in the Application LRA Section 2.3.3.8 describes the diesel generator building ventilation (DGBV) system which is designed to provide filtered, tempered air to the diesel generator building and the SBO diesel generator building. The DGBV System is normally in operation. The purpose of the DGBV System is to remove heat generated by the diesel engines and other heat generating components within the diesel generator building and the SBO diesel generator building and to maintain a controlled environment for personnel and operating equipment during all modes of operation. The DGBV System accomplishes this by supplying both outside air and recirculated air to rooms within the diesel generator building and the SBO diesel generator building. LRA Table 2.3.3-8 identifies the components subject to an AMR for the DGBV system by component type and intended function.2.3.3.8.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the DGBV system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21 (a)(1).2.3.3.9 Emergency Diesel Generators and Auxiliary Systems 2.3.3.9.1 Summary of Technical Information in the Application LRA Section 2.3.3.9 describes the emergency diesel generators and auxiliary systems (EDGA)which consist of the following plant systems: emergency diesel generators (mechanical aspects), emergency diesel generator fuel systems and emergency diesel generator support systems. The EDGA systems are designed to supply electrical power to key plant components when normal offsite power sources are not available. The EDGA systems are standby mechanical systems designed to provide the motive force for generating electrical power for key plant components during events when normal offsite power sources are not available. The EDGA systems accomplish this by utilizing diesel engines to rotate electric generators. Fuel supply, air supply, and cooling water piping and components support emergency diesel engine operation. 2-45 2.3.3.7.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concludes there is reasonable assurance that the applicant has appropriately identified the CH system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1 ). 2.3.3.8 Diesel Generator Building Ventilation System 2.3.3.8.1 Summary of Technical Information in the Application LRA Section 2.3.3.8 describes the diesel generator building ventilation (DGBV) system which is designed to provide filtered, tempered air to the diesel generator building and the SBO diesel generator building. The DGBV System is normally in operation. The purpose of the DGBV System is to remove heat generated by the diesel engines and other heat generating components within the diesel generator building and the SBO diesel generator building and to maintain a controlled environment for personnel and operating equipment during all modes of operation. The DGBV System accomplishes this by supplying both outside air and recirculated air to rooms within the diesel generator building .and the SBO diesel generator building. LRA Table 2.3.3-8 identifies the components subject to an AMR for the DGBV system by component type and intended function. 2.3.3.8.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and* applicable boundary drawings, the staff concludes that the applicant has appropriately identified the DGBV system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21 (a)(1). 2;3.3.9 Emergency Diesel Generators and Auxiliary Systems 2.3.3.9.1 Summary of Technical Information in the Application LRA Section 2.3.3.9 describes the emergency diesel generators and auxiliary systems (EDGA) which consist of the following plant systems: emergency diesel generators (mechanical aspects), emergency diesel generator fuel systems and emergency diesel generator support systems. The EDGA systems are designed to. supply electrical power to key plant components when normal offsite power sources are not available. The EDGA systems are standby mechanical systems designed to provide the motive force for generating electrical power for key plant components during events when normal offsite power sources are not available. The EDGA systems accomplish this by utilizing diesel engines to rotate electric generators. Fuel supply, air supply, and cooling water piping and components support emergency diesel engine operation. 2-45 LRA Table 2.3.3-9 identifies the components subject to an AMR for the EDGA Systems by component type and intended function.2.3.3.9.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.9 and UFSAR Section 8.2.3 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions pursuant to 16 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 has not 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 2.3.3.9 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results.In RAI 2.3.3.9-1, dated August 20, 2008, the staff noted that on license renewal drawing LR-302-351, the EDG air start system air compressor has a standby diesel engine used to drive the compressor in the event of a failure of the electric motor shown as not included within the scope of license renewal. The standby diesel engine includes a tank and lines containing diesel fuel. In accordance with LRA Section 2.1.5.2, the applicant used the preventive option approach to scope nonsafety-related components with a potential for physical or spatial interaction with safety-related SSCs. The preventive option is based on a spaces approach. Potential spatial interaction was assumed in any structure that contains safety-related SSCs. Nonsafety-related systems and components that contain water, oil, or steam, and that are located inside structures that contain safety-related SSCs, are included within scope for potential spatial interaction under criterion 10 CFR 54.4(a)(2), unless located in an excluded room. The standby diesel engine to the EDG air start compressor includes lines containing diesel fuel. In accordance with the applicant's methodology as described in LRA Section 2.1.5.2, this component should be included within scope under 10 CFR 54.4(a)(2). The staff requested that the applicant provide additional information to justify the exclusion of the fluid-filled tank and lines on the standby diesel engine for the EDG air start system air compressor from the scope of license renewal under 10 CFR 54.4(a)(2). In its response to the RAI, dated September 16, 2008, the applicant stated that the fuel tank for the standby diesel engine on license renewal drawing LR-302-351 should have been included in scope and subject to an AMR. The applicant amended the LRA by adding the component type"Tank (Standby Diesel Engine)" with an intended function of leakage boundary to LRA Table 2.3.3-9 and by adding the same component type to LRA Table 3.3.2-9 with complete AMR results. The standby diesel engine fuel lines components, e.g., piping, fittings, hoses, fuel filters, and fuel pump casing are included in the EDGA systems, LRA Tables 2.3.3-9 and 3.3.2-9 under the component types "Filter Housing," "Hoses," "Piping and Fittings," and "Pump Casing (Engine-driven Fuel Oil Pump)." Based on its review, the staff finds the applicant's response to RAI 2.3.3.9-1 acceptable because the applicant included the standby diesel engine fuel tank and fuel line components in scope for license renewal and subject to an AMR. The applicant amended the LRA by adding the component "Tank (Standby Diesel Engine)" with an intended function of leakage boundary to LRA Tables 2.3.3-9 and 3.3.2-9. The staffs concern described in RAI 2.3.3.9-1 is resolved.2-46 LRA Table 2.3.3-9 identifies the components subject to an AMR for the EDGA Systems by component type and intended function. 2.3.3.9.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.9 and UFSAR

8.2.3 using

the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. , During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not o,mitted from the scope of license renewal any componentsi;with intended functions pursuant to 1Q 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 has not 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 2.3.3.9 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. In RAI 2.3.3.9-1, dated August 20, 2008, the staff noted that on license renewal drawing LR-302-351, the EDG air start system air compressor has a standby diesel engine used to drive the compressor in the event of a failure of the electric motor shown as not included within the scope of license renewal. The standby diesel engine includes a tank and lines containing diesel fuel. In accordance with LRA Section 2.1..5.2, the applicant used the preventive option approach to scope nonsafety-related components with a potential for physical or spatial interaCtion with related SSCs. The preventive option is based on a spaces approach. Potential spatial interaction was assumed in any structure that contains safety-related SSCs. Nonsafety-related systems and components that contain water, oil, or steam, and that are located inside structures that contain safety-related SSCs, are included within scope for potential spatial interaction under criterion 10 CFR 54.4(a)(2), unless located in an excluded room. The standby diesel engine to the EDG air start compressor includes lines containing diesel fuel. In accordance with the applicant's methodology as described in LRA Section 2.1.5.2, this component should be included within . scope under 10 CFR 54.4(a)(2). The staff requested that the applicant provide additional information to justify the exclusion of the fluid-filled tank and lines on the standby diesel engine for the EDG air start system air compressor from the scope of license renewal under 10 CFR 54.4(a)(2). In its response to the RAI, dated 16,2008, the applicant stated that the fuel tank for the standby diesel engine on license renewal drawing LR-302-351 should have been included in scope and subject to an AMR. The applicant amended the LRA by adding the component type "Tank (Standby Diesel Engine)" with an intended function of leakage boundary to LRA Table 2.3.3-9 and by adding the same component type to LRA Table 3.3.2-9 with complete AMR .. results. The standby diesel engine fuel lines components, e.g., piping, fittings, hoses, fuel filters, and fuel pump casing are included in the EDGA systems, LRA Tables 2.3.3-9 and 3.3.2-9 under the component types "Filter Housing," "Hoses," "Piping and Fittings," and "Pump Casing driven Fuel Oil Pump)." Based on its review, the staff finds the applicant's response to RAI 2.3.3.9-1 acceptable because the applicant included the standby diesel engine fuel tank and fuel line components in scope for license renewal and subject to an AMR. The applicant amended the LRA by adding the component "Tank (Standby Diesel Engine)" with an intended function of leakage boundary to LRA Tables 2.3.3-9 and 3.3.2-9. The staffs concern described in RAI 2.3.3.9-1 is resolved. 2-46 2.3.3.9.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the EDGA system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).

2. 3.3.10 Fire Protection System 2.3.3.10.1 Summary of Technical Information in the Application LRA Section 2.3.3.10 describes the fire protection system, which is a normally operating mechanical system designed to provide for the rapid detection and suppression of a fire at the plant. It consists of several plant systems, including the fire detection systems, wall openings and fire stops, fire protection systems, fire protection service water, cardox fire extinguisher system for the cable room, and halon systems.The fire protection system includes the fire protection service water system, which consists of deluge, wet pipe, and pre-action sprinkler systems, interior hose reels, and yard hydrants. The fire protection system also consists of halogenated and carbon dioxide fire suppression systems, portable fire extinguishers, fire detection and alarm systems, and the reactor coolant pump lube oil collection system. The physical plant design features include fire barrier walls and slabs, fire barrier penetration seals, fire doors and dampers, fire-rated enclosures, heat shields, combustible gas detectors, and acetylene monitoring equipment.

The purpose of the fire protection system is to reduce the likelihood of fire occurrences, promptly detect and extinguish fires if they occur, maintain capability to safely shut down the plant in the event of a fire, and prevent the subsequent release of a significant amount of radioactive material in the event of a fire. The fire protection system accomplishes this by providing fire protection in the form of detection, alarms, fire barriers, and suppression for selected areas of the plant.The intended functions of the fire protection system within the scope of license renewal are to provide a primary containment boundary, to be dependable in safety analysis or plant evaluations, and to resist nonsafety-related SSC failure.LRA Table 2.3.3-10 identifies the components subject to an AMR for the fire protection system by component type and intended function.2.3.3.10.2Staff EvaluationThe 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 andUFSAR 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 thosecomponents that the applicant identified as within the scope of license renewal to verify that the applicant had not omitted any passive or long-lived components subject to an AMR in accordance with 10 CFR 54.21(a)(1).The staff also reviewed the fire protection CLB documents listed in Operating License Condition 2.c.4.2-47 2.3.3.9.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the EDGA system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.10 Fife Protection System 2.3.3.10.1 Summary of Technical Information in the Application LRA Section 2;3.3.10 describes the fire protection system, which is a normally operating mechanical system designed to provide for the rapid detection and suppression of a fire at the plant. It consists of several plant systems, including the fire detection systems, wall openings and fire stops, fire protection systems, fire protection service water, cardox fire extinguisher system for the cable room, and halon systems. The fire protection system includes the fire protection service water system, which consists of deluge, wet pipe, and pre-action sprinkler systems, interior hose reels, and yard hydrants. The fire protection system also consists of halogenated and carbon dioxide fire suppression systems, portable fire extinguishers, fire detection and alarm systems, and the reactor coolant pump lube oil collection system. The physical plant design features include fire barrier walls and slabs, fire barrier penetration seals, fire doors and dampers, fire-rated enclosures, heat shields, combustible gas detectors, and acetylene monitoring equipment. The purpose of the fire protection system is to reduce the likelihood of fire occurrences, promptly detect and extinguish fires if they occur, maintain capability to safely shut down the plant in the event of a fire, and prevent the subsequent release of a significant amount of radioactive material in the event.of a fire. The fire protection system accomplishes this by providing fire protection in the form of detection, alarms, fire barriers, and suppression for selected areas of the plant. The intended functions of the fire protection system within the scope of license renewal are to provide a primary containment boundary, to be dependable in safety analysis or plant evaluations, and to resist nonsafety-related SSC failure. LRA Table 2.3.3-10 identifies the components subject to an AMR for the fire protection system by component type and intended function. 2.3.3.1 0.2Staff 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 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 the applicant had not omitted any passive or long-lived components subject to an AMR in accordance with 10 CFR 54.21(a)(1). The staff also reviewed the fire protection CLB documents listed in Operating License Condition 2.c.4. 2-47 The staff also reviewed commitments to 10 CFR Part 50.48, "fire protection" (i.e., approved fire protection program), responses to Appendix A to Branch Technical Position (BTP), Auxiliary and Power Conversion Systems Branch (APCSB) 9.5-1, "Guidelines for Fire Protection for Nuclear Power Plants," May 1, 1976, documented in the UFSAR.During its review of LRA Section 2.3.3.10, the staff identified areas in which additional information was necessary to complete its review of the applicant's scoping and screening results.In RAI 2.3.3.10-1, dated August 22, 2008, the staff noted that LRA Tables 2.3.3-10 and 3.3.2-10 exclude several types of fire protection components that are discussed in the SERs or UFSAR, and which also appear on the license renewal drawings as within the scope of license renewal.These components are listed below: " hose connections

  • hose racks* yard hose houses* interior fire hose stations* pipe supports* buried piping* filter housing* flexible hose* dikes for oil spill confinement
  • buried underground fuel oil tanks for emergency diesel generators
  • fire water main loop valves* post indicator valves* lubricating oil collection system components for each reactor coolant pump" lubricating oil cooler* auxiliary lubricating oil makeup tank* 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" thermal insulation on valves* engine intake and exhaust silencers/muffler (diesel driven fire pump)* heat exchangers (bonnet)* heat exchangers (shell)* heat exchangers (tube)The staff requested that the applicant provide additional information to verify whether the components listed above should be included in LRA Tables 2.3.3-10 and 3.3.2-10.

If they are excluded from the scope of license renewal and not subject to an AMR, the staff requested that the applicant provide justification for the exclusion. In its response to the RAI, dated September 19, 2008, the applicant provided the results of'scoping and screening for the listed fire protection system component types as follows: 2-48 The staff also reviewed commitments to 10 CFR Part 50.48, "fire protection" (Le., approved fire protection program), responses to Appendix A to Branch Technical Position (BTP), Auxiliary and Power Conversion Systems Branch (APCSB) 9.5-1, "Guidelines for Fire Protection for Nuclear Power Plants," May 1, 1976, documented in the UFSAR. During its review of LRA Section 2.3.3.10, the staff identified areas in which additional inforljllation was necessary to complete its review of the applicant's scoping and screening results. : In RAI2.3.3.10-1, dated August 22,2008, the staff noted that LRA Tables 2.3.3-10 and 3.3)2-10 exclude several types of fire protection components that are discussed in the SERs or UFSAR, and which also appear on the license renewal drawings as within the scope of license renewal. These components are listed below:

  • hose connections
  • hose racks
  • yard hose houses
  • interior fire hose stations
  • pipe supports
  • buried piping
  • filter housing
  • flexible hose
  • dikes for oil spill confinement
  • buried underground fuel oil tanks for emergency diesel generators
  • fire water main loop valves
  • post indicator valves
  • lubricating oil collection system components for each reactor coolant pump
  • lubricating oil cooler
  • auxiliary lubricating oil makeup tank
  • 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
  • thermal insulation on valves
  • engine intake and exhaust silencers/muffler (diesel driven fire pump)
  • heat exchangers (bonnet)
  • heat exchangers (shell)
  • heat exchangers (tube) The staff requested that the applicant provide additional information to verify whether the . components listed above should be included in LRA Tables 2.3.3-10 and 3.3.2-10.

If they are excluded from the scope of license renewal and not subject to an AMR, the staff requested i:that the applicant provide justification for the exclusion. In its response to the RAI, dated September 19, 2008, the applicant provided the results of . scoping and screening for the listed fire protection system component types as follows: 2-48 Hose connections -Hose connections are included in the "piping and fittings" component category in LRA Tables 2.3.3-10 and 3.3.2-10 Hose racks -Hose rack stations include valves, couplings, and fittings that are included in the "valve body" and "piping and fittings" component categories in LRA Tables 2.3.3-10 and 3.3.2-10. Although pressure tested in accordance with NUREG-1801 program requirements, the linen fire hose is considered consumable and is not subject to an AMR.Yard hose houses -Yard hose houses are nonsafety-related structures not credited with aging management of fire protection components for TMI-1 license renewal and are not subject to an AMR.Interior fire hose stations -Hose stations include valves, couplings, and fittings that are included in the "valve body" and "piping and fittings" component categories in LRA Tables 2.3.3-10 and 3.3.2-10. Although pressure is tested in accordance with NUREG-1801 program requirements, the linen fire hose is considered consumable and is not subject to an AMR." Pipe supports -Pipe supports are included under the component type of "support members, welds, bolted connections, and support anchorage to building structure" in the"component supports commodity group" in LRA Table 2.4-17.* Buried piping -Buried fire protection piping is included in the "piping and fittings"component category in LRA Tables 2.3.3-10 and 3.3.2-10, with an environment of "soil (external)" in LRA Table 3.3.2-10.

  • Filter housing -Filter housings are included in the component category of "strainer body" in LRA Tables 2.3.3-10 and 3.3.2-10." Flexible hose -The only (non-fire water) flexible hoses in the TMI fire protection system are part of the fire suppression system and are included in the "piping and fittings"component category in LRA Tables 2.3.3-10 and 3.3.2-10, with a material of "polymer" in LRA Table 3.3.2-10.

Fire water hoses are considered consumable and are not subject to an AMR." Dikes for oil spill confinement -Dikes for oil spill confinement are included in thecomponent category of "concrete curbs" in LRA Tables 2.3.3-10 and 3.3.2-10, with an intended function of "fire barrier (contain oil spills)."" Buried underground fuel oil tanks for emergency diesel generators -The buried 30,000-gallon fuel oil tank for the emergency diesel generators is evaluated under the emergency diesel generators and auxiliary systems in LRA Table 2.3.3-9. The diesel fuel storage tanks for the diesel-driven fire pumps are above-ground tanks, evaluated with the fuel oil system in LRA Table 2.3.3-12.* Fire water main loop valves -Fire water system valves are included in the "valve body" component type in LRA Tables 2.3.3-10 and 3.3.2-10.* Post indicator valves -Fire water system valves are included in the "valve body" component type in LRA Tables 2.3.3-10 and 3.3.2-10.2-49* Hose connections -Hose connections are included in the "piping and fittings" component category in LRA Tables 2.3.3-10 and 3.3.2-10

  • Hose racks -Hose rack stations include valves, couplings, and fittings that are included in . the "valve body" and "piping and fittings" component categories in LRA Tables 2.3.3-10 and 3.3.2-10.

Although pressure tested in accordance with NUREG-1801 program requirements, the linen fire hose is considered consumable and is not subject to an AMR.

  • Yard hose houses -Yard hose houses are nonsafety-related structures not credited with . aging management of fire protection components for TMI-1 license renewal and are not subject to an AMR.
  • Interior fire hose stations -Hose stations include valves, couplings, and fittings that are included in the "valve body" and "piping and fittings" component categories in LRA Tables 2.3.3-10 and 3.3.2-10.

Although pressure is tested in accordance with NUREG-1801 program requirements, the linen fire hose is considered consumable and is not subject to an AMR. -* Pipe supports -Pipe supports are included under the component type of "support members, welds, bolted connections, and support anchorage to building structure" in the "component supports commodity group" in LRA Table 2.4-17.

  • Buried piping -Buried fire protection piping is included in the "piping and fittings" component category in LRA Tables 2.3.3-10 and 3.3.2-10, with an environment of "soil (external)" in LRA Table 3.3.2-10.
  • Filter housing -Filter housings are included in the component category of "strainer body" in LRA Tables 2.3.3-10 and 3.3.2-10. .
  • Flexible hose -The only (non-fire water) flexible hoses in the TMI fire protection system are part of the fire suppression system and are included in the "piping and fittings" component category in LRA Tables 2.3.3-10 and 3.3.2-10, with a material of "polymer" in LRA Table 3.3.2-10.

Fire water hoses are considered consumable and are not subject to an AMR.

  • Dikes for oil spill confinement

-Dikes for oil spill confinement are included in the component category of "concrete curbs" in LRA Tables 2.3.3-10 and 3.3.2-10, with an intended function of "fire barrier (contain oil spills)."

  • Buried underground fuel oil tanks for emergency diesel generators

-The buried 30,000-gallon fuel oil tank for the emergency diesel generators is evaluated under the emergency diesel generators and auxiliary systems in LRA Table 2.3.3-9. The diesel fuel storage tanks for the diesel-driven fire pumps are above-ground tanks, evaluated with the fuel oil system in LRA Table 2.3.3-12.

  • Fire water main loop valves -Fire water system valves are included in the "valve body" component type in LRA Tables 2.3.3-10 and 3.3.2-10.
  • Post indicator valves -Fire water system valves are included in the "valve body" component type in LRA Tables 2.3.3-10 and 3.3.2-10.

2-49

  • Lubricating oil collection system components for each reactor coolant pump -These components are found under the "piping and fittings," "drip pan," "valve body," and "tanks (RC pump lube oil drain tanks)" component categories in LRA Tables 2.3.3-10 and 3.3.2-10.* Lubricating oil cooler -This component is considered an integral subcomponent part of the fire pump diesel engine, which is considered an active component in accordance with NUREG-1800, Revision 1, Table 2.1-5, Item No. 55, and is not subject to an AMR.* Auxiliary lubricating oil makeup tank -The TMI-1 fire protection system does not have auxiliary lubricating oil makeup tanks. The diesel engines for the fire pumps have oil! sump pans that are integral subcomponents of the fire pump diesel engines, which are considered active components in accordance with NUREG-1800 Revision 1, Table 2.1-5, Item No. 55, and are not subject to aging management review.* Floor drains and curbs for fire-fighting water -Floor drains are evaluated with the miscellaneous floor and equipment drains system in LRA Table 2.3.3-18.

Concrete curbing for flood control is included with the dike/flood control system in LRA Table 2.4-6.* Backflow prevention devices -These components are included in the "valve body" component type in LRA Tables 2.3.3-10 and 3.3.2-10.Flame retardant coating for cables -Thermo-lag and mecatiss fire wrap systems are evaluated under the component type "fire barriers (fire-rated enclosures)" in LRA Tables 2.3.3-10 and 3.3.2-10.* Fire retardant coating for structural steel supporting walls and ceilings -These items are evaluated as insulation under "structural commodities" in LRA Table 2.4-13.

  • Thermal insulation on valves -Thermal insulation is evaluated under "structural commodities" in LRA Table 2.4-13." Engine intake and exhaust silencers/muffler (diesel-driven fire pump) -These components are considered integral subcomponent parts of the fire pump diesel engines which are considered active components in accordance with NUREG-1800, Revision 1, Table 2.1-5, Item No. 55, and are not subject to an AMR.* Heat exchanger (bonnet, shell, and tube) -These components are considered integral subcomponent parts of the fire pump diesel engines, which are considered active components in accordance with NUREG-1800, Revision 1, Table 2.1-5, Item No. 55, and are not subject to an AMR.In reviewing the applicant's response to the RAI, the staff found that each item in the RAI was addressed and resolved as follows.Although the description of the "piping and fittings" line item provided in LRA Table 2.3.3-10 does not list these components specifically, the applicant states that it considers the hose connections, buried piping, flexible hose, and lubricating oil collection system components as included in LRA Table 2.3.3-10 under the component type "piping and fittings," with the AMR results provided in LRA Table 3.3.2-10.2-50* Lubricating oil collection system components for each reactor coolant pump -These components are found under the "piping and fittings," "drip pan," "valve body," and "tanks (RC pump lube oil drain tanks)" component categories in LRA Tables 2.3.3-10 and 3.3.2-10.
  • Lubricating oil cooler -This component is considered an integral subcomponent part of the fire pump diesel engine, which is considered an active component in accordance with NUREG-1800, Revision 1, Table 2.1-5, Item No. 55, and is not subject to an AMR. .
  • Auxiliary lubricating oil makeup tank -The TMI-1 fire protection system does not have auxiliary lubricating oil makeup tanks. The diesel engines for the fire pumps have oili sump pans that are integral sUbcomponents of the fire pump diesel engines, which are considered active components in accordance with NUREG-1800 Revision 1, Table 2.1-5, Item No. 55, and are not subject to aging management review.
  • Floor drains and curbs for fire-fighting water -Floor drains are evaluated with the miscellaneous floor and equipment drains system in LRA Table 2.3.3-18.

Concrete* curbing for flood control is included with the dike/flood control system in LRA Table 2.4-6.

  • Backflow prevention devices -These components are included in the "valve body" component type in LRA Tables 2.3.3-10 and 3.3.2-10.
  • Flame retardant coating for cables -Thermo-lag and mecatiss fire wrap systems are evaluated under the component type "fire barriers (fire-rated endosures)" in LRA Tables 2.3.3-10 and 3.3.2-10.
  • Fire retardant coating for structural steel supporting walls and ceilings -These items are evaluated as insulation under "structural commodities" in LRA Table 2.4-13.
  • Thermal insulation on valves -Thermal insulation is evaluated under "structural commodities" in LRA Table 2.4-13.
  • Engine intake and exhaust silencers/muffler (diesel-driven fire pump) -These components are considered Integral subcomponent parts of the fire pump diesel engines which considered active components in accordance with NUREG-1800, Revision 1, Table 2.1-5, Item No. 55, and are not subject to an AMR.
  • Heat exchanger (bonnet, shell, and tube) -These components are considered integral subcomponent parts of the fire pump diesel engines, which are considered active components in accordance with NUREG-1800, Revision 1, Table 2.1-5, Item No. 55, and are not subject to an AMR. In reviewing the applicant's response to the RAI, the staff found that each item in the RAI was addressed and resolved as follows. II Although the description of the "piping and fittings" line item provided in LRA Table 2.3.3-10 does not list these components specifically, the applicant states that it considers the hose connections, buried piping, flexible hose, and lubricating oil collection system components as included in LRA Table 2.3.3-10 under the component type "piping and fittings," with the AMR results provided in LRA Table 3.3.2-10.

2-50 Further, the applicant states that it considers the hose racks, interior hose stations, fire water main loop valves, post-indicator valves, and backflow prevention devices as included in LRA Table 2.3.3-10 under the component type "valve body," with the AMR results provided in LRA Table 3.3.2-10. Pipe supports are included under the component type of "support members," in LRA Table 2.4-17, "component supports commodity group." Filter housings are included in the component category of "strainer body" in LRA Tables 2.3.3-10 and 3.3.2-10. Dikes for oil spill confinement are included in the LRA Tables 2.3.3-10 and 3.3.2-10 under "concrete curbs." Floor drains and curbs for fire-fighting water are addressed in LRA Table 2.3.3-18, "miscellaneous floorand equipment drain system." Flame retardant coating for cables is included under components type "fire barrier" in LRA Tables 2.3.3-10 and 3.3.2-10. Fire retardant coating for structural steel supporting walls and ceilings and thermal insulation on valves are included under "structural commodities" in LRA Table 2.4-13. Buried underground fuel oil tanks for emergency diesel generators are evaluated under"emergency diesel generators and auxiliary systems" in LRA Table 2.3.3-9.The staff finds this portion of the applicant's response to RAI 2.3.3.10-1 acceptable because it confirmed that the components in question are within the scope of license renewal and subject to an AMR. The response also directed the staff to the AMR results in the LRA.The staff found that the applicant appropriately excluded the following components from the line item descriptions in the LRA because these components are active, and therefore not subject to an AMR: (a) lubricating oil cooler, (b) engine intake and exhaust silencers/muffler (diesel driven fire pump), and (c) heat exchanger (bonnet, shell, and tube).Auxiliary lubricating oil makeup tanks are not part of the fire protection systems in TMI-1. Since these components are not used in the fire protection systems at TMI-1, the staff finds that these components were appropriately omitted from the scope of license renewal.The staff found that the yard hose houses are not within the scope of license renewal and subject-to an AMR, and were not included in the line item descriptions in the LRA table. The yard fire hydrants are housed in small sheds storing tools and the accompanying fire hydrant fire hoses.Failure of a hose house, which is a second level support system, need not be considered in determining the SCs within the scope of the rule under 10 CFR 54.4(a)(3). The staff found yard hose houses were correctly excluded from the scope of license renewal and not subject to an AMR.Based on its review, the staff finds the applicant's response to RAI 2.3.3.10-1 acceptable, because it addresses the staff's concerns regarding scoping, screening, and AMR of fire protection system components listed in the RAI. The staff's concerns described in RAI 2.3.3.10-1 are resolved.2.3.3.10.3 Conclusion The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether or not the applicant failed to identify any SCs within the scope of license renewal. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the fire protection system components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1). 2-51 Further, the applicant states that it considers the hose racks, interior hose stations, fire water main loop valves, post-indicator valves, and backflow prevention devices as included in LRA Table 2.3.3-10 under the component type "valve body," with the AMR results provided in LRA Table 3.3.2-10. Pipe supports are included under the component type of "support members," in LRA Table 2.4-17, "component supports commodity group." Filter housings are included in the component category of "strainer body" in LRA Tables 2.3.3-10 and 3.3.2-10. Dikes for oil spill confinement are included in the LRA Tables 2.3.3-10 and 3.3.2-10 under "concrete curbs." Floor drains and curbs for fire-fighting water are addressed in LRA Table 2.3.3-18, "miscellaneous floor and equipment drain system." Flame retardant coating for cables is included under components type "fire barrier" in LRA Tables 2.3.3-10 and 3.3.2-10. Fire retardant coating for structural steel supporting walls and ceilings and thermal insulation on valves are included under "structural commodities" in LRA Table 2.4-13. Buried underground fuel oil tanks for emergency diesel generators are evaluated under "emergency diesel generators and auxiliary systems" in LRA Table 2.3.3-9. The staff finds this portion of the applicant's response to RAI 2.3.3.10-1 acceptable because it confirmed that the components in question are within the scope of license renewal and subject to an AMR. The response also directed the staff to the AMR results in the LRA. The staff found that the applicant appropriately excluded the following components from the line item descriptions in the LRA because these components are 'active, and therefore not subject to an AMR: (a) lubricating oil cooler, (b) engine intake and exhaust silencers/muffler (diesel driven fire pump), and (c) heat exchanger (bonnet, shell, and tube). Auxiliary lubricating oil makeup tanks are not part of the fire protection systems in TMI-1. Since these components are not used in the fire protection systems at TMI-1, the staff finds that these components were appropriately omitted from the scope of license renewal. Thestafffound that the yard hose houses are not within the scope of license renewal and subject to an AMR, and were not included in the line item descriptions in the LRA table. The yard fire hydrants are housed in small sheds storing tools and the accompanying fire hydrant fire hoses. Failure of a hose house, which IS a second level support system, need not be considered in determining the SCs within the scope of the rule under 10 CFR 54.4(a)(3). The staff found yard hose houses were correctly excluded from the scope of license renewal and not subject to an AMR. ' Based on its review, the staff finds the applicant's response to RAI 2.3.3.10-1 acceptable, because it addresses the staff's concerns regarding scoping, screening, and AMR of fire protection system components listed in the RAI. The staff's concerns described in RAI 2.3.3.10-1 are resolved. 2.3.3.10.3 Conclusion The staff reviewed the LRA, UFSAR, RAI responses, and drawings to determine whether or not the applicant failed to identify any SCs within the scope of license renewal. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the fire protection system components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1). 2-51 2.3.3.11 Fuel Handling and Fuel Storage System 2.3.3.11.1 Summary of Technical Information in the Application LRA Section 2.3.3.11 describes the fuel handling and fuel storage (FHS) system which consists of the following plant systems: fuel handling system, new fuel racks, and spent fuel racks. The purpose of the FHS system is to control fuel storage positions to assure a geometrically safe configuration with respect to criticality, ensure adequate shielding of irradiated fuel for plant personnel to accomplish normal operations, prevent mechanical damage to the stored fuel that could result in significant release of radioactivity from the fuel, and provide means for the safe handling of new and irradiated fuel assemblies. The FHS System accomplishes this by using storage racks to safely and securely hold new and irradiated fuel in the spent fuel pool, and by using the fuel handling bridges, cranes, and other transfer equipment to move fuel. The FHS System is used during fuel movement to, from, and within the reactor vessel or the spent fuelpools, and to store new and spent fuel. LRA Table 2.3.3-11 identifies the components subject to an AMR for the FHS System by component type and intended function.2.3.3.11.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concludes there is reasonable assurance that the applicant has appropriately identified the FHS system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.12 Fuel Oil System 2.3.3.12.1 Summary of Technical Information in the Application LRA Section 2.3.3.12 describes the fuel oil (FO) system, as an auxiliary system designed to store and transfer diesel fuel oil. The FO system is a standby mechanical system designed to receive, store, and transfer diesel fuel oil for use in the auxiliary boilers, emergency diesel generators, diesel fire pumps, substation emergency diesel generators, and the fire training facility. The FO system accomplishes this by providing storage tanks, transfer pumps, and piping for diesel fuel oil storage and transfer. LRA Table 2.3.3-12 identifies the components subject to an AMR for the FO system by component type and intended function.2.3.3.12.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concludes there is reasonable assurance that the applicant has appropriately identified the FO system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the systemcomponents subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2-52 2.3.3.11 Fuel Handling and Fuel Storage System 2.3.3.11.1 Summary of Technical Information in the Application LRA Section 2.3.3.11 describes the fuel handling and fuel storage (FHS) system which consists of the following plant systems: fuel handling system, new fuel racks, and spent fuel racks. The purpose of the FHS system is to control fuel storage positions to assure a geometrically safe configuration with respect to criticality, ensure adequate shielding of irradiated fuel for plant personnel to accomplish normal operations, prevent mechanical damage to the stored fuel that could result in significant release of radioactivity from the fuel, and provide means for the safe handling of new and irradiated fuel assemblies. The FHS System accomplishes this by using storage racks to safely and securely hold new and irradiated fuel in the spent fuel pool, and by using the fuel handling bridges, cranes, and other transfer equipment to move fuel. The FHS System is used during fuel movement to, from, and within the reactor vessel or the spent fuel pools, and to store new and spent fuel. LRA Table 2.3.3-11 identifies the components subject to an AMR for the FHS System by component type and intended function. 2.3.3.11.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of theLRA and UFSAR, the staff concludes there is reasonable assurance that the applicant has appropriately identified the FHS system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.12 Fuel Oil System 2.3.3.12.1 Summary of Technical Information in the Application , LRA Section 2.3.3.12 describes the fuel oil (Fa) system, as an auxiliary system designed to store and transfer diesel fuel oil. The Fa system is a standby mechanical system designed to redbive, . store, and transfer diesel fuel oil for use in the auxiliary boilers, emergency diesel generatons, diesel fire pumps, substation emergency diesel generators, and the fire training facility. Thel FO system accomplishes this by providing storage tanks, transfer pumps, and piping for diesel :fuel oil I, storage and transfer. LRA Table 2.3.3-12 identifies the components subject to an AMR for the Fa system by component type and intended function. 2.3.3.12.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the iLRA and UFSAR, the staff concludes there is reasonable assurance that the applicant has appropriately identified the Fa system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21 (a)(1). 2-52 2.3.3.13 Hydrogen Monitoring System 2.3.3.13.1 Summary of Technical Information in the Application LRA Section 2.3.3.13 describes the hydrogen monitoring (HM) System. The purpose of the HM system is to monitor hydrogen concentration inside the reactor building during accident and post-accident conditions. The HM system accomplishes this by circulating a sample of the reactor building atmosphere through piping and hydrogen analyzers and calculating the hydrogen concentration of that sample. The HM system is not in service during normal operation, although it is available at all times. LRA Table 2.3.3-13 identifies the components subject to an AMR for the HM system by component type and intended function.2.3.3.13.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concludes there is reasonable assurance that the applicant has appropriately identified the HM system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21 (a)(1).2.3.3.14 Instrument and Control Air System 2.3.3.14.1 Summary of Technical Information in the Application LRA Section 2.3.3.14 describes the instrument & control air system which is a mechanical system designed to continuously deliver clean, dry pressurized air throughout the plant. The instrument &control air system includes two plant systems: the plant instrument air system, which includes the backup instrument air and two hour backup instrument air plant sub-systems; and the plant service air system. The instrument & control air system is in scope for license renewal.The instrument & control air system supplies air to virtually every system in the plant. The system consists of compressors, air dryers, filters, receivers, inter and after coolers, storage cylinders, piping, valves and supporting instrumentation. The boundary with these systems extends up to and includes the air operator and positioner of the end user system components, such as valves, dampers and pneumatic instrumentation. The function of the system is to continuously deliver clean, dry, pressurized air in sufficient quantities to points throughout the plant. The system utilizes a main air compressor, which in normal operation is sufficient to supply clean, dry air to plant instrument air users. When the main compressor is lost or is unable to maintain pressure, two oil free standby instrument air compressors are available, each discharging through a separate after-cooler and air receiver to a common air dryer. Two lubricated plant service air compressors provide additional backup. If instrument air system pressure continues to drop, air will automatically flow from the Service Air System, through an oil removal filter and then to the Instrument Air dryer to provide dry air to the plant.The function of the backup instrument air system (BUIAS) is to supply undried air to critical secondary plant components on a loss of pressure. There are two BUIAS compressors and associated distribution headers, one located in the turbine building and one located in the intermediate building. The BUIAS compressor supplies air to a distribution header in the turbine 2-53 2.3.3.13 Hydrogen Monitoring System 2.3.3.13.1 Summary of Technical Information in the Application LRA Section 2.3.3.13 describes the hydrogen monitoring (HM) System. The purpose of the HM system is to monitor hydrogen concentration inside the reactor building during accident and accident conditions. The HM system accomplishes this by circulating a sample of the reactor building atmosphere through piping and hydrogen analyzers and calculating the hydrogen concentration of that sample. The HM system is not in service during normal operation, although it is available at all times. LRA Table 2.3.3-13 identifies the components subject to an AMR for the HM system by component type and intended function. 2.3.3.13.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concludes there is reasonable assurance that the applicant has appropriately identified the HM system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.14 Instrument and Control Air System 2.3.3.14.1 Summary of Technical Information in the Application LRA Section 2.3.3.14 describes the instrument & control air system which is a mechanical system designed to continuously deliver clean, dry pressurized air throughout the plant. The instrument & control air system includes two plant systems: the plant instrument air system, which includes the backup instrument air and two hour backup instrument air plant sub-systems; and the plant service air system. The instrument & control air system is in scope for license renewal. The instrument & control air system supplies air to virtually every system in the plant. The system consists of compressors, air dryers, filters, receivers, inter and after coolers, storage cylinders, piping, valves and supporting instrumentation. The boundary with these systems extends up to and includes the air operator and positioner of the end user system components, such as valves, dampers and pneumatic instrumentation. The function of the system is to continuously deliver clean, dry, pressurized air in sufficient quantities to points throughout the plant. The system utilizes a main air compressor, which in normal operation is sufficient to supply clean, dry air to plant instrument air users. When the main compressor is lost or is unable to maintain pressure, two oil free standby instrument air compressors are available, each discharging through a separate after-cooler and air receiver to a common air dryer. Two lubricated plant service air compressors provide additional backup. If instrument air system pressure continues to drop, air will automatically flow from the Service Air System, through an oil removal filter and then to the Instrument Air dryer to provide dry air to the plant. The function of the backup instrument air system (BUIAS) is to supply undried air to critical secondary plant components on a loss of pressure. There are two BUIAS compressors and associated distribution headers, one located in the turbine building and one located in the intermediate building. The BUIAS compressor supplies air to a distribution header in the turbine 2-53 building to allow equipment critical to plant shutdown to function. The BUIAS compressor supplies air to a distribution header in the intermediate building to allow the feedwater control valves and the main steam atmospheric dump valves to function.The main function of the two hour backup instrument air system (2HBUIAS) is to provide compressed air for operation of components within the main steam, reactor river and emergency feedwater systems upon the loss of the instrument air system which may result from a design basis event such as a high energy line break, loss of offsite power, station blackout, or seismic event that could preclude reactor decay heat removal via the emergency feedwater and main steam systems.The 2HBUIAS supplies components in the main steam, reactor river and emergency feedwater systems from two independent trains. An air compressor is provided to supply dry, filtered air to maintain the two hour air bank bottle pressure between 1700 and 2250 psig.The compressor is operated manually when the air banks are charged. The function of the plant service air system is to provide convenient outlets throughout the plant for general compressed air use and to provide backup source of compressed air to the instrument air system.LRA Table 2.3.3-14 identifies the components subject to an AMR for the instrument & control air system by component type and intended function.2.3.3.14.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.14 and UFSAR Sections 5.1.1, 5.3.5, 7.1.4.3, 7.3.2.2, 9.10.1, and 9.10.3 using the evaluation methodology described in SER Section 2.3 and the, guidance in SRP-LR Section 2.3.During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions 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 the applicant has not 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 2.3.3.14 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results.In RAI 2.3.3.14-1, dated August 20, 2008, the staff noted that on license renewal drawing LR-302-276, the two-hour backup IA charging compressor is not highlighted, indicating that the charging compressor was not included within the scope of license renewal. The charging compressor includes an oil pump and piping containing oil that operates up to 1500 psi, and is located in the EDG room, which contains safety-related equipment. Similar to the discussion in RAI 2.3.3.9-1, in accordance with the applicant's methodology, nonsafety-related systems and components that contain water, oil, or steam, and are located inside structures that contain!safety-related SSCs, are included within scope of license renewal for potential spatial interaction under criterion 10 CFR 54.4(a)(2). In accordance with the applicant's methodology as described in LRA Section 2.1.5.2, the charging compressor should be included within scope of license renewal under 10 CFR 54.4(a)(2). The staff requested that the applicant provide additional:' information to justify the exclusion of the backup IA charging compressor from the scope of license renewal under 10 CFR 54.4(a)(2). 2-54 building to allow equipment critical to plant shutdown to function. The BUIAS compressor supplies air to a distribution header in the intermediate building to allow the feedwater control valves and the main steam atmospheric dump valves to function. The main function of the two hour backup instrument air system (2HBUIAS) is to provide compressed air for operation of components within the main steam, reactor river and emergency feedwater systems upon the loss of the instrument air system which may result from a design basis event such as a high energy line break, loss of offsite power, station blackout, or seismic event that could preclude reactor decay heat removal via the emergency feedwater and main steam systems. The 2HBUIAS supplies components in the main steam, reactor river and emergency feedwater systems from two independent trains. An air compressor is provided to supply dry, filtered air to maintain the two hour air bank bottle pressure between 1700 and 2250 psig. ' The compressor is operated manually when the air banks are charged. The function of the plant service air system is to provide convenient outlets throughout the plant for general air use and to provide backup source of compressed air to the instrument air system. LRA Table 2.3.3-14 identifies the components subject to an AMR for the instrument & cont(ol air system by component type and intended function. 2.3.3.14.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.14 and UFSAR Sections 5.1.1, 5.3.5,7.1.4.3,7.3.2.2" 9.10.1, and 9.10.3 using the evaluation methodology described in SER Section 2.3 and the,; guidance in SRP-LR Section 2.3. During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any 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 the applicant ha's not omitted any passive and long-lived components subject to an AMR, in accordance with ! 10 CFR54.21(a)(1). The staffis review of LRA Section 2.3.3.14 identified areas in which additional*information was necessary to complete the review of the applicant's scoping and screening results. In RAI 2.3.3.14-1, dated August 20, 2008, the staff noted that on license renewal drawing LR-302-276, the two-hour backup IA charging compressor is not highlighted, indicating that the charging compressor was not included within the scope of license renewal. The charging compressor includes an oil pump and piping containing oil that operates up to 1500 psi, an,d is located in the EDG room, which contains safety-related equipment. Similar to the discussion in RAI 2.3.3.9-1, in accordance with the applicant's methodology, nonsafety-related systems components that contain water, oil, or steam, and are located inside structures that contail'1' safety-related SSCs, are included within scope of license renewal for potential spatial interaction undercriterion 10 CFR 54.4(a)(2). In accordance with the applicant's methodology as described in LRA Section 2.1.5.2, the charging compressor should be includec:l within scope of renewal under 10 CFR 54.4(a)(2). The staff requested that the applicant provide additional information to justify the exclusion of the backup IA charging compressor from the scope of license renewal under 10 CFR 54.4(a)(2). 2-54 In its response to the RAI, dated September 16, 2008, the applicant stated the oil lines associated with the two-hour backup IA charging compressor should have been included in the scope of license renewal for leakage boundary piping on license renewal drawing LR-302-276. The applicant amended the LRA by adding the component "Piping and Fittings (Two Hour Backup Instrument Air Charging Compressor)" with an intended function of leakage boundary to LRA Table 2.3.3-14 and adding the same component type to LRA Table 3.3.2-14 with complete AMR results. In addition, the applicant amended the environments list and the aging management programs list in LRA Section 3.3.2.1.14 to add lubricating oil and an AMP: "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," respectively. On October,23, 2008, the staff conducted a conference call with the applicant to discuss their response to RAI 2.3.3.14-1. As a result of the phone conference, the applicant clarified that in LRA Section 3.3.2.1.14, "lubricating oil" should have been listed under "Environments List" and not "Materials." The staff concurred with this correction. Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-1 acceptable because the applicant added the component "Piping and Fittings (Two Hour Backup Instrument Air Charging Compressor)" with an intended function of leakage boundary to LRA Tables 2.3.3-14 and 3.3.2-14. In addition, the applicant amended LRA Section 3.3.2.1.14 to add "lubricating oil" to the environments list and an AMP: "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" to the aging management programs list. Therefore, the staff s concern described in RAI 2.3.3.14-1 is resolved.In RAI 2.3.3.14-2, dated August 20, 2008, the staff noted that on license renewal drawing LR-302-271, the IA piping to a temperature instrument connected to after-cooler IA-C-1 B is not highlighted, indicating that it is not within the scope of license renewal. The IA piping from the IA cooler to the temperature sensor is part of the pressure boundary of the IA system and should be included within scope in accordance with 10 CFR 54.4(a)(1). The IA piping up to a similar temperature instrument connected to after-cooler IA-C-1A is highlighted in green, indicating that it is within the scope of license renewal. The staff requested that the applicant provide additionalinformation to justify the exclusion of the piping to the temperature instrument connecting to IA after-cooler IA-C-I B from the scope of license renewal., In its response to the RAI, dated September 16, 2008, the applicant stated the IA piping up to and including the temperature instrument located on the after-cooler IA-C-1 B on license renewal drawing LR-302-271 is included within the scope of license renewal, and the piping should have been highlighted on the license renewal drawing.On October 23, 2008, the staff conducted a conference call with the applicant AmerGen to discuss their response to RAI 2.3.3.14-2 and RAI 2.3.3.17-2. As a result of the phone conference, the applicant clarified that they do not intend to make physical changes to license renewal drawings to correct license renewal drawing errors. Rather, the applicant will provide a sufficient description of needed license renewal drawing changes to adequately respond to an RAI. The staff concurred with the applicant's proposal and will submit RAIs to document any license renewal drawing discrepancy accordingly. Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-2 acceptable because the applicant clarified that the piping up to and including the temperature instrument located on the IA after-cooler IA-C-i B is included in the scope of license renewal; therefore, the staff's concern described in RAI 2.3.3.14-2 is resolved.2-55 In its response to the RAI, dated September 16, 2008, the applicant stated the oil lines associated with the two-hour backup IA charging compressor should have been included in the scope of license renewal for leakage boundary piping on license renewal drawing LR-302-276. The applicant amended the LRA by adding the component "Piping and Fittings (Two Hour Backup Instrument Air Charging Compressor)" with an intended function of leakage boundary to LRA Table 2.3.3-14 and adding the same component type to LRA Table 3.3.2-14 with complete AMR results. In addition, the applicant amended the environments list and the aging management programs list in LRA Section 3.3.2.1.14 to add lubricating oil and an AMP: "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," respectively. On October r 23, 2008, the staff conducted a conference call with the applicant to discuss their response to RAI 2.3.3.14-1. As a result of the phone conference, the applicant clarified that in LRA Section 3.3.2.1.14, "lubricating oil" should have been listed under "Environments List" and not "Materials." The staff concurred with this correction. Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-1 acceptable because . the applicant added the component "Piping and Fittings (Two Hour Backup Instrument Air Charging Compressor)" with an intended function of leakage boundary to LRA Tables 2.3.3-14 and 3.3.2-14. In addition, the applicant amended LRA Section 3.3.2.1.14 to add "lubricating oil" to the environments list and an AMP: "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" to the aging management programs list. Therefore, the staff's concern described in RAI2.3.3.14-1 is resolved. In RAI 2.3.3.14-2, dated August 20, 2008, the staff noted that on license renewal drawing LR-302-271, the IA piping to a temperature instrument connected to after-cooler IA-C-1 B is not highlighted, indicating that it is not within the scope of license renewal. The IA piping from the IA cooler to the temperature sensor is part of the pressure boundary of the IA system and should be included within scope in accordance with 10 CFR 54.4( a)( 1). The IA piping up to a similar temperature instrument connected to after-cooler IA-C-1A is highlighted in green, indicating that it within the scope of license renewal. The staff requested that the applicant provide additional information to justify the exclusion of the piping to the temperature instrument connecting to IA after-cooler IA-C-1 B from the scope of license renewal. ' In its response to the RAI, dated September 16,2008, the applicant stated the IA piping up to and including the temperature instrument located on the after-cooler IA-C-1 B on license renewal drawing LR-302-271 is included within the scope of license renewal, and the piping should have been highlighted on the license renewal drawing. On October 23, 2008, the staff conducted a conference call with the applicant AmerGen to discuss their response to RAI 2.3.3.14-2 and RAI 2.3.3.17-2. As a result of the phone conference, the applicant clarified that they do not intend to make physical changes to license renewal drawings to correct license renewal drawing errors. Rather, the applicant will provide a sufficient description of needed license renewal drawing changes to adequately respond to an RAI. The staff concurred with the applicant's proposal and will submit RAls to document any license renewal drawing discrepancy accordingly. Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-2 acceptable because the applicant clarified that the piping up to and including the temperature instrument located on the IA after-cooler IA-C-1 B is included in the scope of license renewal; therefore, the staff's concern described in RAI 2.3.3.14:-2 is resolved. 2-55 2.3.3.14.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the instrument and control air system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.15 Intake Screen and Pump House Ventilation System 2.3.3.15,1 Summary of Technical Information in the Application LRA Section 2.3.3.15 describes the intake screen and pump house ventilation (ISPV) system.The ISPV system is designed to provide tempered air to the intake screen and pump house. The purpose of the ISPV system is to provide filtered, tempered air to safety-related areas of the intake screen and pump house during normal plant operation. The ISPV system accomplishes this by supplying both outside and recirculated air to rooms within the intake screen and pump house. LRA Table 2.3.3-15 identifies the components subject to aging management review~for the ISPV system by component type and intended function.2.3.3.15.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the ISPV system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.16 Intermediate Building Ventilation System 2.3.3.16.1 Summary of Technical Information in the Application LRA Section 2.3.3.16 describes the intermediate building ventilation (IBV) system which consists of the intermediate building heating & ventilation system and emergency feedwater pump rooms cooling system. The purpose of the IBV system is to provide filtered, tempered air to the intermediate building. The IBV system accomplishes this by recirculating tempered air throughout the intermediate building. LRA Table 2.3.3-16 identifies the components subject to an AMR for the IBV system by component type and intended function.2.3.3.16.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the IBV system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2-56 2.3.3.14.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the instrument and control air system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). . 2.3.3.15 Intake Screen and Pump House Ventilation System 2.3.3.15.1 Summary of Technical Information in the Application LRA Section 2.3.3.15 describes the intake screen and pump house ventilation (ISPV) system. The ISPV system is designed to provide tempered air to the intake screen and pump house. The purpose of the ISPV system is to provide filtered, tempered air to safety-related areas of the intake screen and pump house during normal plant operation. The ISPV system accomplishes this by supplying both outside and recirculated air to rooms within the intake screen and pump house. LRA Table 2.3.3-15 identifies the components subjectto aging management review ,for the ISPV system by component type and intended function. 2.3.3.15.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has, appropriately identified the ISPV system mechanical components within the scope of renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.16 Intermediate Building Ventilation System 2.3.3.16.1 Summary of Technical Information in the Application LRA Section 2.3.3.16 describes the intermediate building ventilation (IBV) system which consists of the intermediate building heating & ventilation system and emergency feedwater pump rooms cooling system. The purpose of thelBV system is to provide filtered, tempered air to the, intermediate building. The IBV system accomplishes this by recirculating tempered air throyghout the intermediate building. LRA Table 2.3,3-16 identifies the components subject to an AMRifor the IBV system by component type and intended function. 2.3.3.16.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the ILRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the IBV system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1 ). 2-56 2.3.3.17 Liquid and Gas Sampling System 2.3.3.17.1 Summary of Technical Information in the Application LRA Section 2.3.3.17 describes the liquid and gas sampling (LGS) system which consists of the following plant systems: nuclear liquid sampling system, radgas sampling system, turbine plant sampling system, auxiliary boiler sampling system, and post accident sampling system. The LGS system is an auxiliary system designed to provide liquid, steam, and gas samples of plant processes for chemical and radiochemical analysis. The LGS system accomplishes this by transporting samples from the plant systems being sampled to the sampling sinks.LRA Table 2.3.3-17 identifies the components subject to an AMR for the Liquid and Gas Sampling System by component type and intended function.2.3.3.17.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.17, UFSAR Section 9.2.2, and UFSAR Tables 5.3-2 and 7.1-2 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions 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 the applicant has not 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 2.3.3.17 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. In RAI 2.3.3.17-1 dated August 20, 2008, the staff noted that on license renewal drawing LR-302-181 the primary sampling coolers tube side components are highlighted in red, indicating that they are within the scope of license renewal based on 10 CFR 54.4(a)(2) criteria. On license renewal drawing LR-302-181 the condensate pump sample cooler tube side components are highlighted in red, indicating that they are within the scope of license renewal based on 10 CFR 54.4(a)(2) criteria. Note 3 on license renewal drawing LR-302-181 reads: "The tube side of the Sample Coolers is evaluated for aging management with the LGS System. The shell side of the coolers is evaluated for aging management with the CCCW System." However, LRA Table 2.3.3-17 does not list these coolers as subject to an AMR. Note 4 on license renewal drawing LR-302-181 reads: "The tube side of the Condensate Pump Sample Cooler is evaluated for aging management with the LGS System. The shell side of the cooler is evaluated for aging management with the CCCW System." However, LRA Table 2.3.3-17 does not list this cooler as subject to an AMR. The staff requested that the applicant provide the following additional information: " Justify the exclusion of the tube side of the primary sampling coolers from LRA Table 2.3.3-17 as a component subject to an AMR.* Justify the exclusion of the tube side of the condensate pump sample cooler from LRA Table 2.3.3-17 as a component subject to an AMR.2-57 2.3.3.17 Liquid and Gas Sampling System 2.3.3.17.1 Summary of Technical Information in the Application lRA Section 2.3.3.17 describes the liquid and gas sampling (lGS) system which consists of the following plant systems: nuclear liquid sampling system, radgas sampling system, turbine plant sampling system, auxiliary boiler sampling system, and post accident sampling system. The LGS system is an auxiliary system designed to provide liquid, steam, and gas samples of plant processes for chemical and radiochemical analysis. The LGS system accomplishes this by transporting samples from the plant systems being sampled to the sampling sinks. lRA Table 2.3.3-17 identifies the components subject to an AMR for the Liquid and Gas Sampling System by component type and intended function. 2.3.3.17.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.17, UFSAR Section 9.2.2, and UFSAR Tables 5.3-2 and 7.1-2 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions 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 the applicant has not omitted any passive and long-lived components subject to an AMR, in accordance with 10CFR 54.21(a)(1). The staffs review of LRA Section 2.3.3.17 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. In RAI 2.3.3.17-1 dated August 20, 2008, the staff noted that on license renewal drawing LR-302-181 the primary sampling coolers tube side components are highlighted in red, indicating that they are within the scope of license renewal based on 10 CFR 54.4(a)(2) criteria. On license renewal drawing LR-302-181 the condensate pump sample cooler tube side components are highlighted in red, indicating that they are within the scope of license renewal based on 10 CFR 54.4(a)(2) criteria. Note 3 on license renewal drawing LR-302-181 reads: "The tube side of the Sample Coolers is evaluated for aging management with the LGS System. The shell side of the coolers is evaluated for aging management with the CCCW System." However, LRA Table 2.3.3-17 does not list these coolers as subject to an AMR. Note 4 on license renewal drawing LR-302-181 reads:. "The tube side of the Condensate Pump Sample Cooler is evaluated for aging management with the LGS System. The shell side of the cooler is evaluated for aging management with the CCCW System." However, LRA Table 2.3.3-17 does not list this cooler as subject to an AMR. The staff requested that the applicant provide the following additional information:

  • Justify the exclusion of the tube side of the primary sampling coolers from LRA Table 2.3.3-17 as a component subject to an AMR.
  • Justify the exclusion of the tube side of the condensate pump sample cooler from LRA Table 2.3.3-17 as a component subject to an AMR. 2-57 In its response to the RAI, dated September 16, 2008, the applicant stated that the primary sample coolers on license renewal drawing LR-302-181 are tube in tube coolers and the inner tubes, which were incorrectly shown in red, are contained within the outer tubes. The applicant further stated that the nonsafety-related inner tube side of the coolers do not perform any intended functions; therefore, they are not in scope, and that the inner tube side should have been depicted in black, indicating the inner tube side is not in scope for license renewal. The applicant indicated that Note 3 on license renewal drawing LR-302-181 should have stated: "The Primary Sample Coolers are evaluated for aging management with the CCCW System." The applicant stated that the primary sample coolers are not listed in LRA Table 2.3.3-17 because theinner tube side of the coolers does not perform an intended function and the outer tube side of the coolers, which performs a leakage boundary intended function, is evaluated with the CCCW system and listed in LRA Table 2.3.3-4.

On October 23, 2008, the staff conducted a conference call with the applicant to discuss their response to RAI 2.3.3.17-1. As a result of the teleconference, the applicant clarified that for table revisions that only include one item or a very minor change, they have not been showing the table revisions in the RAI response, rather providing a description of the revision instead. The staff concurred with the applicant's response.Based on its review, the staff finds the applicant's response to the first part of RAI 2.3.3.17-1 acceptable because the applicant clarified that the primary sample coolers are evaluated with the CCCW system and that the inner tube side of the coolers do not perform an intended function with respect to license renewal, but the outer tube side of the coolers perform a leakage boundary intended function and are listed in LRA Table 2.3.3-4 CCCW. The staff's concern described in the first part of RAI 2.3.3.17-1 is resolved.In addressing the second part of RAI 2.3.3.17-1, the applicant stated the condensate pump sample cooler is a "tube in tube" cooler and that the outer tube of the cooler performs a leakage boundary intended function and is correctly shown in red on license renewal drawing LR-302-181; however, it was omitted from LRA Tables 2.3.3-17 and 3.3.2-17. The applicant also stated that the nonsafety-related inner tube side of the coolers do not perform any intended functions; therefore, they are not in scope and that the inner tubes are contained within the outer tubes and were incorrectly shown in red. The applicant indicated that the inner tube side should have been depicted in black, indicating the inner tube side is not in scope for license renewal. The applicant indicated that Note 4 on license renewal drawing LR-302-181 should have stated: "The Condensate Pump Sample Cooler is evaluated for aging management with the LGS System." The applicant amended the LRA by adding the component "Heat exchanger components (Condensate Pump Sample Cooler)" with an intended function of leakage boundary to LRA Table 2.3.3-17 and by adding the same component type to LRA Table-3.3.2-17 with complete aging management review results. In addition, the applicant stated that the AMP: "External Surfaces Monitoring Program" will be used to manage loss of material due to general corrosion of the condensate pump sample cooler and that LRA Table 3.3.1 Item 3.3.1-58 should include the LGS system in the discussion list of applicable systems for the External Surfaces Monitoring Program.Based on its review, the staff finds the applicant's response to the second part of RAI 2.3.3.17-1 acceptable because the applicant clarified that the condensate pump sample cooler is evaluated with the LGS system, and that the inner tubes of the cooler are not within scope for license.renewal, but the outer tube side of the cooler performs a leakage boundary intended function and is in scope for license renewal. Hence, the applicant amended the LRA by adding the component"Heat exchanger components (Condensate Pump Sample Cooler)" with an intended function of leakage boundary to LRA Tables 2.3.3-17 and 3.3.2-17. In addition, the applicant clarified that 2-58 In its response to the RAI, dated September 16, 2008, the applicant stated that the primary sample coolers on license renewal drawing LR-302-181 are tube in tube coolers and the inner tubes, which were incorrectly shown in red, are contained within the outer tubes. The applicant further stated that the nonsafety-related inner tube side of the coolers do not perform any** intended functions; therefore, they are not in scope, and that the inner tube side should have been depicted in black, indicating the inner tube side is not in scope for license renewal. The applicant indicated that Note 3 on license renewal drawing LR-302-181 should have stated: "The Primary Sample Coolers are evaluated for aging management with the CCCW System." The applicant stated that the primary sample coolers are not listed in LRA Table 2.3.3-17 because the inner tube side of the coolers does not perform an intended function and the outer tube side of the coolers, which performs a leakage boundary intended function, is evaluated with the CCCW system and listed in LRA Table 2.3.3-4. On October 23, 2008, the staff conducted a conference call with the applicant to discuss their response to RAI 2.3.3.17-1. As a result of the teleconference, the applicant clarified that for table revisions that only include one item or a very minor change, they have not been showing the table . revisions in the RAI response, rather providing a description of the revision instead. The concurred with the applicant's response. . Based on its review, the staff finds the applicant's response to the first part of RAI 2.3.3.17-1 acceptable because the applicant clarified that the primary sample coolers are evaluated with the CCCW system and that the inner tube side of the coolers do not perform an intended function with respect to license renewal, but the outer tube side of the coolers perform a leakage boundary intended function and are listed in LRA Table 2.3.3-4 CCCW. The staff's concern described in the first part of RAI 2.3.3.17-1 is resolved. In addressing the second part of RAI 2.3.3.17-1, the applicant stated the condensate pump sample cooler is a "tube in tube" cooler and that the outer tube of the cooler performs a leakage boundary intended function and is correctly shown in red on license renewal drawing LR-302-181; however, it was omitted from LRA Tables 2.3.3-17 and 3.3.2-17. The applicant also stated that the nonsafety-related inner tube side of the coolers do not perform any intended functions; therefore, they are not in scope and that the inner tubes are contained within the outer tubes and were incorrectly shown in red. The applicant indicated that the inner tube side should have been depicted in black, indicating the inner tube side is not in scope for license renewal. The applicant indicated that Note 4 on license renewal drawing LR-302-181 should have stated: "The Condensate Pump Sample Cooler is evaluated for aging management with the LGS System." The applicant amended the LRA by adding the component "Heat exchanger components (Condensate Pump Sample Cooler)" with an intended function of leakage boundary to LRA Table 2.3.3-17 and by adding the same component type to LRA Table-3.3.2-17 with complete aging review results. In addition, the applicant stated that the AMP: "External Surfaces Monitoring Program" will be used to manage loss of material due to general corrosion of the condensate pump sample cooler and that LRA Table 3.3.1 Item 3.3.1-58 should include the LGS system in the discussion list of applicable systems for the External Surfaces Monitoring Program. Based on its review, the staff finds the applicant's response to the second part of RAI 2.3.3.17-1 acceptable because the applicant clarified that the condensate pump sample cooler is evaluated with the LGS system, and that the inner tubes of the cooler are not within scope for license: renewal, but the outer tube side of the cooler performs a leakage boundary intended function and is in scope for license renewal. Hence, the applicant amended the LRA by adding the component "Heat exchanger components (Condensate Pump Sample Cooler)" with. an intended function of leakage boundary to LRA Tables 2.3.3-17 and 3.3.2-17. In addition, the applicant clarified that 2-58 LRA Table 3.3.1 Item 3.3.1-58 includes the LGS system in the discussion list of applicable systems for the External Surfaces Monitoring Program. The staff's concern described in the second part of RAI 2.3.3.17-1 is resolved.In RAI 2.3.3.17-2, dated August 20, 2008, the staff noted that on license renewal drawing LR-302-182 the chillers are highlighted in red, indicating that they are within the scope of license renewal based on 10 CFR 54.4(a)(2) criteria. Note 3 on license renewal drawing LR-302-182 reads: "The tube side and shell side of the Chillers are evaluated for Aging Management with the LGS System." However, LRA Table 2.3.3-17 does not list these chillers as subject to an AMR. The staff requested that the applicant provide additional information to justify the exclusion of the tube side and shell side of the chillers from LRA Table 2.3.3-17 as a component subject to an AMR.In its response to the RAI, dated September 16, 2008, the applicant stated that the secondary sample chillers, SS-C-1 and SS-C-2, are in the scope of license renewal as shown on LR-302-182 and the component type "Heat exchanger components (Secondary Sample Chillers)" should have been included in LRA Tables 2.3.3-17 and 3.3.2-17, but were omitted. The applicant amended the LRA by adding the component "Heat exchanger components (Secondary Sample Chillers)" with an intended function of leakage boundary to LRA Table 2.3.3-17 and added the same component type to LRA Table 3.3.2-17 with complete aging management review results. In addition, the applicant stated that the AMP: "External Surfaces Monitoring Program" will be used to manage loss of material due to general corrosion of the secondary sample chillers; therefore, LRA Table 3.3.1 Item 3.3.1-58 should include the LGS system in the discussion list of applicable systems for the External Surfaces Monitoring Program.Based on its review, the staff finds the applicant's response to RAI 2.3.3.17-2 acceptable because the applicant added component type "Heat exchanger components (Secondary Sample Chillers)" to LRA Tables 2.3.3-17 and 3.3.2-17. In addition, the applicant clarified that LRA Table 3.3.1, item3.3.1-58, includes the LGS system in the discussion list of applicable systems for the External Surfaces Monitoring Program. The staff's concern described in RAI 2.3.3.17-2 is resolved.In RAI 2.3.3.17-3, dated August 20, 2008, the staff noted that on various license renewal drawings, the applicant highlighted piping in red leading up to and out of an enclosure such as a sampling panel, indicating that the piping is within the scope of license renewal based on 10 CFR 54.4(a)(2) criteria; however, neither the piping inside the panel nor the panel enclosure walls are shown as within scope. For example, on license renewal drawing LR-302-181 the iron sampler housing and the sampling rack just below the iron sampler are shown in black. Since these panels contain components that should be subject to an AMR for 10 CFR 54.4(a)(2), and the panel enclosures are not highlighted in red, the staff expects the internal components to be included within the scope of license renewal. The staff requested that the applicant provide additional information to justify the exclusion of the housing panels and their internal piping and components from being within scope for an AMR in accordance with 10 CFR 54.4(a)(2). In addition, the staff requested that the applicant provide additional information to explain how piping and components inside an enclosure are evaluated for inclusion within scope under 10 CFR 54.4(a)(2). In its response to the RAI, dated September 16, 2008, the applicant stated that these enclosures, such as the iron sampler housing, are in the scope of license renewal and evaluated for license renewal in LRA Section 2.4.13, Structural Commodities, as commodity type "Cabinets, Enclosures and Panels for Electrical Equipment and Instrumentation." The applicant stated that its practice was not to highlight structural components on mechanical license renewal drawings. As indicated on license renewal drawing LR-302-181, piping up to the enclosure is required to 2-59 LRA Table 3.3.1 Item 3.3.1-58 includes the LGS system in the discussion list of applicable systems for the External Surfaces Monitoring Program. The staff's concern described in the second part of RAI2.3.3.17-1 is resolved. In RAI 2.3.3.17-2, dated August 20, 2008, the staff noted that on license renewal drawing LR-302-182 the chillers are highlighted in red, indicating that they are within the scope of license renewal based on 10 CFR 54.4(a)(2) criteria. Note 3 on license renewal drawing LR-302-182 reads: "The tube side and shell side of the Chillers are evaluated for Aging Management with the LGS System." However, LRATabie 2.3.3-17 does not list these chillers as subject to an AMR. The staff requested that the applicant provide additional information to justify the exclusion of the tube side and shell side of the chillers from LRA Table 2.3.3-17 as a component subject to an AMR. In its response to the RAI, dated September 16, 2008, the applicant stated that the secondary sample chillers, SS-C-1 and SS-C-2, are in the scope of license renewal as shown on LR-302-182 and the component type "Heat exchanger components (Secondary Sample Chillers)" should have been included in LRA Tables 2.3.3-17 and 3.3.2-17, but were omitted. The applicant amended the LRA by adding the component "Heat exchanger components (Secondary Sample Chillers)" with an intended function of leakage boundary to LRA Table and added the same component type to LRA Table 3.3.2-17 with complete aging management review results. In addition, the applicant stated that the AMP: "External Surfaces Monitoring Program" will be used to manage loss of material due to general corrosion of the secondary sample chillers; therefore, LRA Table 3.3.1 Item 3.3.1-58 should include the LGS system in the discussion list of applicable systems for the External Surfaces Monitoring Program. Based on its review, the staff finds the applicant's response to RAI 2.3.3.17-2 acceptable because the applicant added component type "Heat exchanger components (Secondary Sample Chillers)" to LRA Tables 2.3.3-17 and 3.3.2-17. In addition, the applicant clarified that LRA Table 3.3.1, item 3.3.1-58, includes the LGS system in the discussion list of applicable systems for the External . Surfaces Monitoring Program. The staff's concern described inRAI 2.3.3.17-2 is resolved. In RAI 2.3.3.17-3, dated August 20, 2008, the staff noted that on various license renewal drawings, the applicant highlighted piping in red leading up to and out of an enclosure such as a sampling panel, indicating that the piping is within the scope of license renewal based on 10 CFR 54.4(a)(2) criteria; however, neither the piping inside the panel nor the panel enclosure walls are shown as within scope. For example, on license renewal drawing LR-302-181 the iron sampler housing and the sampling rack just below the iron sampler are shown in black. Since these panels contain components that should be subject to an AMR for 10 CFR 54.4(a)(2), and the panel enclosures are not highlighted in red, the staff expects the internal components to be included within the scope of license renewal. The staff requested that the applicant provide additional information to justify the exclusion of the housing panels and their internal piping and components from being within scope for an AMR in accordance with 10 CFR 54.4(a)(2). In addition, the staff requested that the applicant provide additional information to explain how piping and components inside an enclosure are evaluated for inclusion within scope under 10 CFR 54.4(a)(2). In its response to the RAI, dated September 16,2008, the applicant stated that these enclosures, such as the iron sampler housing, are in the scope of license renewal and evaluated for license renewal in LRA Section 2.4.13, Structural Commodities, as commodity type "Cabinets, Enclosures and Panels for Electrical Equipment and Instrumentation." The applicant stated that its practice was not to highlight structural components on mechanical license renewal drawings. As indicated on license renewal drawing LR-302-181, piping up to the enclosure is required to 2-59 perform a leakage boundary function; therefore, it is subject to AMR for 10 CFR 54.4(a)(2) due to the potential of spatial interaction with safety-related equipment. Piping inside the enclosure does not have a potential for spatial interaction with safety-related equipment, because the enclosure protects the safety-related equipment from spray originating from the nonsafety-related components. On October 23, 2008, the staff conducted a conference call with the applicant to discuss their response to RAI 2.3.3.17-3. As a result of the teleconference, the applicant clarified that their inclusion of panels in the scope of license renewal under 10 CFR 54.4(a)(2) for enclosures to prevent the interaction of non-safety related components with safety related components was not intended to contradict their statement of non-use of the mitigative approach discussed in LRA Section 2.1. The staff reviewed the applicant's response and determined there were no negative effects to the components the applicant included in their scoping or screening process.Based on its review, the staff found the applicant's response to RAI 2.3.3.17-3 acceptable because the applicant clarified that the enclosures protecting safety-related equipment from spray originating from the nonsafety-related components inside are included within the scope of license renewal under 10 CFR 54.4(a)(2) and are evaluated in LRA Section 2.4.13. The staffs concern described in RAI 2.3.3.17-3 is resolved.In RAI 2.3.3.17-4, dated November 24, 2008, the staff noted that in the following instances, the applicant shows the same components highlighted in different colors on different license renewal drawings, reflecting the components being included in the scope of license renewal for different reasons: On license renewal drawing LR-302-181, components CE10 through CE16 and their associated piping are shown highlighted in red; indicating that they are within the scope of license renewal for 10 CFR 54.4(a)(2) criteria. However, on license renewal drawings LR-302-111 and LR-302-01 1, these same components and their associated piping are shown highlighted in green; indicating that they are within the scope of license renewal for 10 CFR 54.4(a)(1) or (a)(3) criteria.On license renewal drawing LR-302-182, components CE17, CE18, CE25 through CE27 and their associated piping are shown highlighted in red; indicating that they are within the scope of license renewal for 10 CFR 54.4(a)(1) or (a)(3) criteria. However, these samecomponents and their associated piping, CE17 and CE18 (license renewal drawing LR-302-111), CE25 (license renewal drawing LR-302-101)and CE26 and CE 27 (license renewal drawing LR-302-1 01), are shown highlighted in green; indicating that they are within the scope of license renewal for 10 CFR 54.4(a)(2) criteria.On license renewal drawing LR-302-671, components CE1 18, CE1 19 and their associated piping, are shown in black; indicating that they are not within the scope of license renewal.However, on license renewal drawing LR-302-640, these same components and their associated piping are shown highlighted in red; indicating that they are within the scope of license renewal for 10 CFR 54.4(a)(2) criteria.On license renewal drawing LR-302-671, components CE100 through CE106 and their associated piping are shown highlighted in red; indicating that they are within the scope of license renewal for 10 CFR 54.4(a)(2) criteria. However, these same components and their associated piping, CE100 through CE104 (license renewal drawing LR-302-719), 2-60 perform a leakage boundary function; therefore, it is subject to AMR for 10 CFR 54.4(a)(2) due to the potential of spatial interaction with safety-related equipment. Piping inside the enclosure does not have a potential for spatial interaction with safety-related equipment, because the enclosure protects the safety-related equipment from spray originating from the nonsafety-related components. On October 23, 2008, the staff conducted a conference call with the applicant to discuss response to RAI 2.3.3.17-3. As a result of the teleconference, the applicant clarified that their inclusion of panels in the scope of license renewal under 10 CFR 54.4(a)(2) for enclosures to prevent the interaction of non-safety related components with safety related components was not intended to contradict their statement of non-use of the mitigative approach discussed in LRA Section 2.1. The staff reviewed the applicant's response and determined there were no negative effects to the components the applicant included in their scoping or screening process. Based on its review, the staff found the applicant's response to RAI 2.3.3.17-3 acceptable because the applicant clarified that the enclosures protecting safety-related equipment from spray originating from the nonsafety-related components inside are included within the scope of license renewal under 10 CFR 54.4(a)(2) and are evaluated in LRA Section 2.4.13. The staff's concern described in RAI 2.3.3.17-3 is resolved. In RAI 2.3.3.17-4, dated November 24,2008, the staff noted that in the following instances,;the applicant shows the same components highlighted in different colors on different license renewal drawings, reflecting the components being included in the scope of license renewal for different reasons:

  • On license renewal drawing LR-302-181, components CE10 through CE16 and their associated piping are shown highlighted in red; indicating that they are within the sc'ope of license renewal for 10 CFR 54.4(a)(2) criteria.

However, on license renewal drawings LR-302-111 and LR-302-011, these same components and their associated piping are shown highlighted in green; indicating that they are within the scope of license renewal for 10 CFR 54.4(a)(1) or (a)(3) criteria. * . On license renewal drawing LR-302-182, components CE17, CE18, CE25 through CE27 and their associated piping are shown highlighted in red; indicating that they are within the scope of license renewal for 10 CFR 54.4(a)(1) or (a)(3) criteria. However, these same components and their associated piping, CEl? and CE18 (license renewal drawing LR-302-111), CE25 (license renewal drawing LR-302-1 01) .and CE26 and CE 27 (license renewal drawing LR-302-1 01), are shown highlighted in green; indicating that they are within the scope of license renewal for 10 CFR 54.4(a)(2) criteria.

  • On license renewal drawing LR-302-671, components CE118, CE119 and their asspciated piping, are shown in black; indicating that they are not within the scope of license renewal. . However, on license renewal drawing LR-302-640, these same components and their associated piping are shown highlighted in red; indicating that they are within the scope of license renewal for 10 CFR 54.4(a)(2) criteria.
  • On license renewal drawing LR-302-671, components CE100 through CE106 and their associated piping are shown highlighted in red; Indicating that they are within the scope of license renewal for 10 CFR 54.4(a)(2) criteria.

However, these same components and their associated piping, CE100 through CE104 (license renewal drawing LR-302-719), 2-60 CE104 (license renewal drawing LR-302-660), and CE105 and CE106 (license renewal drawing LR-302-650), are shown highlighted in green; indicating that they are within the scope of license renewal for 10 CFR 54.4(a)(1) or (a)(3) criteria.Proper identification of components included within the scope of license renewal is necessary to properly identify the intended function and whether additional attached or surrounding equipment needs to be included within the scope of license renewal to support or protect the ability of asafety-related component to perform its safety function. For the components and their associated piping described above, the staff requested the applicant provide additional information to clarify which criteria the components are in scope under 10 CFR 54.4(a) and determine whether additional components are necessary to be brought within the scope of license renewal as a result.In its response to the RAI, dated December 5, 2008, the applicant stated that that CE10 through CE16 and their associated piping are nonsafety-related components that are in scope for 10 CFR 54.4(a)(2) criteria (functional support) and that these components should have been shown in green, but were incorrectly depicted on license renewal drawing LR-302-181 in red. The applicant then explained the extent of the red highlighting on LR-302-181 which should have been shown in green. In conclusion the applicant stated that no additional components were required tobe brought within the scope of license renewal due to the incorrect highlighting. The applicant also stated that CE17, CE18, and CE25 through CE27 and their associated piping are nonsafety-related components that are in scope for 10 CFR 54.4(a)(2) criteria (spatial interaction) and that these components should have been shown in red, but were incorrectly depicted on license renewal drawings LR-302-101 and LR-302-1 11 in green. The applicant then explained the extent of the green highlighting on the two license renewal drawings which should have been shown in red. In conclusion the applicant stated that no additional components were required to be brought within the scope of license renewal due to the incorrect highlighting. The applicant also stated that on- license renewal drawing LR-302-640, CE1 18 and CE1 19 shouldhave been shown in black to match their representations on LR-302-671, which are correctly shown as not in scope for 10 CFR 54.4(a)(2)(spatial interaction) because they are located inside a shielded sample panel. The applicant stated that the piping up to CE1 18 and CE1 19 on license renewal drawing LR-302-640 is correctly shown in red to indicate its inclusion in scope for 10 CFR 54.4(a)(2) criteria (spatial interaction) up to the shielded sample panel. In conclusion the applicant stated that no additional components were required to be brought within the scope of license renewal due to the incorrect highlighting.The applicant also stated that CE100 through CE106 and their associated piping are nonsafety-related components that are in scope for 10 CFR 54.4(a)(2) criteria (functional support)and should be shown in green, but were incorrectly depicted on license renewal drawing LR-302-671 in red. The applicant stated that CE100 through CE106 and their scoping boundaries are correctly depicted in green on the other license renewal drawings referenced in the RAI. In conclusion the applicant stated that no additional components were required to be brought within the scope of license renewal due to the incorrect highlighting. Based on its review, the staff finds the applicant's response to RAI 2.3.3.17-4 acceptable because the applicant clarified which components were required to be scope for license renewal and subject to an AMR, and no additional components were required to be brought within the scope of license renewal. The staff's concerns described in RAI 2.3.3.17-4 are resolved.2-61 CE104 (license renewal drawing LR-302-660), and CE105 and CE106 (license renewal drawing LR-302-650), are shown highlighted in green; indicating that they are within the scope of license renewal for 10 CFR 54.4(a)(1) or (a)(3) criteria. Proper identification of components included within the scope of license renewal is necessary to properly identify the intended function and whether additional attached or surrounding equipment needs to be included within the scope of license renewal to support or protect the ability of a safety-related component to perform its safety function. For the components and their associated piping described above, the staff requested the applicant provide additional information to clarify which criteria the components are in scope under 10 CFR 54.4(a) and determine whether additional components are necessary to be brought within the scope of license renewal as a result. In its response to the RAI, dated December 5,2008, the applicant stated that that CE10 through CE16 and their associated piping are nonsafety-related components that are in scope for 10 CFR 54.4(a)(2) criteria (functional support) and that these components should have been shown in green, but were incorrectly depicted on license renewal drawing LR-302-181 in red. The applicant then explained the extent of the red highlighting on LR-302-181 which should have been shown in green. In conclusion the applicant stated that no additional components were required to be brought within the scope of license renewal due to the incorrect highlighting. The applicant also stated that CE17, CE18, and CE25 through CE27 and their associated piping are non safety-related components that are in scope for 10 CFR 54.4(a)(2) criteria (spatial interaction) and that these components should have been shown in red, but were incorrectly depicted on license renewal drawings LR-302-101 and LR-302-111 in green. The applicant then explained the extent of the green highlighting on the two license renewal drawings which should have been shown in red. In conclusion the applicant stated that no additional components were required to be brought within the scope of license renewal due to the incorrect highlighting. The applicant also stated that on license renewal drawing LR-302-640, CE118 and CE119 should haye been shown in black to match representations on LR-302-671, which are correctly shown as not in scope for 10 CFR 54.4(a)(2)(spatial interaction) because they are located inside a shielded sample panel. The applicant stated that the piping up to CE 118 and CE 119 on license renewal drawing LR-302-640 is correctly shown in red to indicate its inclusion in scope for 10 CFR 54.4(a)(2) criteria (spatial interaction) up to the shielded sample panel. In conclusion the applicant stated that no additional components were required to be brought within the scope of license renewal due to the incorrect highlighting. The applicant also stated that CE100 through CE106 and their associated piping are nonsafety-related components that are in scope for 10 CFR 54.4(a)(2) criteria (functional support) and should be shown in green, but were incorrectly depicted on license renewal drawing LR-302-671 in red. The applicant stated that CE100 through CE106 and their scoping boundaries are correctly depicted in green on the other license renewal drawings referenced in the RAI. In conclusion the applicant stated that no additional components were required to be brought within the scope of license renewal due to the incorrect highlighting. Based on its review, the staff finds the applicant's response to RAI 2.3.3.17-4 acceptable because the applicant clarified which components were required to be scope for license renewal and subject to an AMR, and no additional components were required to be brought within the scope of license renewal. The staff's concerns described in RAI 2.3.3.17-4 are resolved. 2-61 In RAI 2.3.3.17-5, dated November 24, 2008, the staff noted that on license renewal drawing LR-302-671, the piping leading up to and the valves CA-V998, CA-V99A, CA-V95 and CA-V109 are shown in black; indicating that they are not within the scope of license renewal. However, these piping segments connect directly to various 3/8 inch piping shown highlighted in red; indicating that these other various piping segments are within the scope of license renewal for 10 CFR 54.4(a)(2) criteria. Since there is no apparent physical barrier and the piping is directly attached to other piping that is included in the scope of license renewal under 10 CFR 54.4(a)(2), then this piping and valves should also be included in the scope of license renewal. The staff requested the applicant provide additional information to justify the exclusion of the piping and valves from the scope of license renewal and subject to AMR with the intended function of leakage boundary.In its response to the RAI, dated December 5, 2008, the applicant stated that the LGS system scoping boundary, which includes potentially liquid filled lines outside of sample hoods and shielded sample panels, is incorrectly shown on license renewal drawing LR-302-671. The applicant stated that the system scoping boundary includes the piping to valves CA-V95,CA-V99A, CA-V99B and CA-V1 09 and continues through four additional valves to the associated 3/8 inch piping that is physically located outside the sample hood and ends at the LGS system to miscellaneous floor and equipment drains system boundary flag. The applicant discussed additional valves, piping and tubing runs shown on license renewal drawing LR-302-671, which also should have been highlighted as within the scope of license renewal. In conclusion, the applicant stated that the components discussed in the response should have been highlighted in red, indicating they are in the scope of license renewal for 10 CFR 54.4(a)(2) criteria (spatial interaction). Based on its review, the staff finds the applicant's response to RAI 2.3.3.17-5 acceptable because the applicant clarified that the piping and valves identified in the RAI should have been included in the scope of license renewal for 10 CFR 54.4(a)(2) criteria with an intended function of spatial interaction. The staff's concern described in RAI 2.3.3.17-5 is resolved.In RAI 2.3.3.17-6, dated November 24, 2008, the staff noted that on license renewal drawing LR-302-671 the applicant shows valves CA-V32A, CA-V32B, CA-V337, CA-V47, CA-V48, CA-V53, CA-V59, CA-V61, CA-V64A, CA-V67A, CA-V64B, CA-67B, CA-V70, CA-V73, CA-V78, CA-V75,CA-V82A, CA-V82B, CA-V80, CA-V85A, and CA-V85B in black; indicating that they are not within the scope of license renewal. However, immediately before these valves, the piping is shown highlighted in red; indicating that the piping is within the scope of license renewal for 10 CFR 54.4(a)(2) criteria with an intended function of leakage boundary. There must be a method of isolating the piping components that are within the scope of license renewal for leakage boundary from the piping components that are not within scope. This isolation can be achieved by a valve, which can be closed and is within scope, or by a physical barrier. The staff requested the applicant provide additional information to justify the exclusion of the listed valves from the scope of license renewal and subject to aging management for an intended function of leakage boundary.In its response to the RAI, dated December 5, 2008, the applicant stated that valves CA-V32A and CA-V32B, OTSG sample coolers CA-C-2A and CA-C-2B, valves CA-V51A and CA-V51B, and associated piping to the sample hood wall downstream, are nonsafety-related components that perform a leakage boundary intended function within the scope of license renewal for 10 CFR 54.4(a)(2) criteria and should be shown in red instead of black on license renewal drawing LR-302-671. The applicant also stated the OTSG sample coolers are evaluated for 2-62 In RAI 2.3.3.17-5, dated November 24, 2008, the staff noted that on license renewal drawing LR-302-671, the piping leading up to and the valves CA-V99B, CA-V99A, CA-V95 and CA-V109 are shown in black; indicating that they are not within the scope of license renewal. However, these piping segments connect directly to various 3/8 inch piping shown highlighted in red; indicating that these other various piping segments are within the scope of license renewal for 10 CFR 54.4(a)(2) criteria. Since there is no apparent physical barrier and the piping is directly attached to other piping that is included in the scope of license renewal under 10 CFR 54.4(a)(2), then this piping and valves should also be included in the scope of license renewal. The staff . requested the applicant provide additional information to justify the exclusion of the piping and valves from the scope of license renewal and subject to AMR with the intended function of leakage boundary. In its response to the RAI, dated December 5,2008, the applicant stated that the LGS system scoping boundary, which includes potentially liquid filled lines outside of sample hoods and ,: shielded sample panels, is incorrectly shown on license renewal drawing LR-302-671. The' applicant stated that the system scoping boundary includes the piping to valves CA-V95, CA-V99A, CA-V99B and CA-V109 and continues through four additional valves to the associated 3/8 inch piping that is physically located outside the sample hood and ends at the LGS to miscellaneous floor and equipment drains system boundary flag. The applicant discussed additional valves, piping and tubing runs shown on license renewal drawing LR-302-671, wtJich also should have been highlighted as within the scope of license renewal. In conclusion, the applicant stated that the components discussed in the response should have been highlighted in red, indicating they are in the scope of license renewal for 10 CFR 54.4(a)(2) criteria (spatial interaction ). Based on its review, the staff finds the applicant's response to RAI 2.3.3.17-5 acceptable because the applicant clarified that the piping and valves identified in the RAI should have been included in the scope of license renewal for 10 CFR 54.4(a)(2) criteria with an intended function of spatial interaction. The staffs concern described in RAI2.3.3.17-5 is resolved. In RAI 2.3.3.17-6, dated November 24, 2008, the staff noted that on license renewal drawing LR-302-671 the applicant shows valves CA-V32A, CA-V32B, CA-V337, CA-V47, CA-V48, CA-V53, CA-V61, CA-V64A, CA-V67A, CA-V64B, CA-67B, CA-V70, CA-V73, CA-V78; CA-V75, CA-V82A, CA-V82B, CA-V80, CA-V85A, and CA-V85B in black; indicating that they are not within the scope of license renewal. However, immediately before these valves, the piping is shown highlighted in red; indicating that the piping is within the scope of license renewal for 10 CFR 54.4(a)(2) criteria with an intended function of leakage boundary. There must be a method of isolating the piping components that are within the scope of license renewal for leakage boundary from the piping components that are not within scope. This isolation can be achieved by a valve, which can be closed and is within scope, or by a physical barrier. The staff requested the . applicant provide additional information to justify the exclusion of the listed valves from the scope " of license renewal and subject to aging management for an intended function of leakage boundary. In its response to the RAI, dated December 5, 2008, the applicant stated that valves and CA-V32B, OTSG sample coolers CA-C-2A and CA-C-2B, valves CA-V51A and CA-V51B, and associated piping to the sample hood wall downstream, are nonsafety-related components that perform a leakage boundary intended function within the scope of license renewal for i 10 CFR 54.4(a)(2) criteria and should be shown in red instead of black on license renewal drawing LR-302-671. The applicant also stated the OTSG sample coolers are evaluated for 2-62 license renewal in the CCCW system as "Heat exchanger components (Pressurizer Sample and OTSG Sample Coolers)" in LRA Tables 2.3.3-4 and 3.3.2.4. Note 2 on LR-302-671 should have included the CCCW system.The applicant also stated that CA-V337 is a nonsafety-related, normally closed valve that performs a leakage boundary intended function within the scope of license renewal for 10 CFR 54.4(a)(2) criteria and should be shown in red instead of black on license renewal drawing LR-302-671. The applicant stated that the piping downstream of CA-V337 is nonsafety-related, not liquid filled and performs no intended function; therefore, it is not within scope of license renewal.The applicant also stated that CA-V47, CA-V48, CA-V1 070, CA2P1, and associated tubing are nonsafety-related, gas filled components and that the valves and associated tubing are not in scope because they are not relied upon to perform a structural support intended function and there is no potential for spatial interaction with safety-related components. The applicant stated that these valves and their associated tubing should have been depicted in black on license renewal drawing LR-302-671, indicating that these components do not perform any intended function and are not in scope for license renewal.The applicant also stated that valves CA-V53, CA-V59, CA-V61, CA-V64A, CA-V67A, CA-V64B, CA-67B, CA-V70, CA-V73, CA-V78, CA-V75, CA-V82A, CA-V82B, CA-V80, CA-V85A, CA-V85B and associated piping are nonsafety-related components that are in the scope of license renewal for 10 CFR 54.4(a)(2) criteria (spatial interaction) and that these components perform a leakage boundary. intended function up to the sample hood wall and should be shown in red instead of black on license renewal drawing LR-302-671. Based on its review, the staff finds the applicant's response to RAI 2.3.3.17-6 acceptable because the applicant clarified which valves and associated components identified in the RAI should have been in scope and subject to an AMR. The staff's concerns described in RAI 2.3.3.17-6 are resolved.2.3.3.17.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the liquid and gas sampling system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.18 Miscellaneous Floor and Equipment Drains System 2.3.3.18.1 Summary of Technical Information in the Application LRA Section 2.3.3.18 describes the miscellaneous floor and equipment drains (MFED) system which consists of the following plant systems: steam generator secondary side blowdown and drains system, sumps and waste collection, turbine building sumps and drains system, auxiliary building sump and drain system, intermediate building sump, circulating water pumphouse sump,air intake tunnel sump, and miscellaneous sumps and drains. The MFED system is an auxiliary system designed to provide drainage control and management to the plant.The purpose of the MFED system is to provide drainage control and management to plant buildings and rooms, provide flood protection to equipment, and provide a flowpath for OTSG sample blowdown to the main condenser. The MFED system accomplishes this by providing 2-63 license renewal in the CCCW system as "Heat exchanger components (Pressurizer Sample and OTSG Sample Coolers)" in LRA Tables 2.3.3-4 and 3.3.2.4. Note 2 on LR-302-671 should have included the CCCW system. The applicant also stated that CA-V337 is a nonsafety-related, normally closed valve that performs a leakage boundary intended function within the scope of license renewal for 10 CFR 54.4{a)(2) criteria and should be shown in red instead of black on license renewal drawing LR-302-671. The applicant stated that the piping downstream of CA-V337 is nonsafety-related, not liquid filled and performs no intended function; therefore, it is not within scope of license renewal. The applicant also stated that CA-V47, CA-V48, CA-V1070, CA2P1, and associated tubing are nonsafety-related, gas filled components and that the valves and associated tubing are not in scope because they are not relied upon to perform a structural support intended function and there is no potential for spatial interaction with safety-related components. The applicant stated that these valves and their associated tubing should have been depicted in black on license renewal drawing LR:302-671, indicating that these components do not perform any intended function and are not in scope for license renewal. The applicant also stated that valves CA-V53, CA-V59, CA-V61, CA-V64A, CA-V67A, CA-V64B, CA-678, CA-V70, CA-V73, CA-V78, CA-V75, CA-V82A, CA-V828, CA-V80, CA-V85A, CA-V858 and associated piping are nonsafety-related components that are in the scope of license renewal for 10 CFR 54.4(a){2) criteria (spatial interaction) and that these components perform a leakage boundary. intended function up to the sample hood wall and should be shown in red instead of black on license renewal drawing LR-302-671. Based on its review, the staff finds the applicant's response to RAI 2.3.3.17-6 acceptable because the applicant clarified which valves and associated components identified in the RAI should have been in scope and subject to an AMR. The staff's concerns described in RAI 2;3.3.17-6 are resolved. 2.3.3.17.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the liquid and gas sampling system components within the scope of license renewal, as required by 10 CFR 54.4{a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21{a){1). 2.3.3.18 Miscellaneous Floor and Equipment Drains System 2.3.3.18.1 Summary of Technical Information in the Application LRA Section 2.3.3.18 describes the miscellaneous floor and equipment drains (MFED) system which consists of the following plant systems: steam generator secondary side blowdown and drains system, sumps and waste collection, turbine building sumps and drains system, auxiliary building sump and drain system, intermediate building sump, circulating water pumphouse sump, air intake tunnel sump, and miscellaneous sumps and drains. The MFED system is an auxiliary system designed to provide drainage control and management to the plant. The purpose of the MFED system is to provide drainage control and management to plant buildings and rooms, provide flood protection to equipment, and provide a flowpath for OTSG sample blowdown to the main condenser. The MFED system accomplishes this by providing 2-63 drains, drain flowpaths, sumps, sump pumps, and discharge flowpaths from buildings and rooms.LRA Table 2.3.3-18 identifies the components subject to aging management review for the miscellaneous floor and equipment drain system by component type and intended function.1, 2.3.3.18.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concludes there is reasonable assurance that the applicant has appropriately identified the MFED system components within the scope of license renewal, 'as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21 (a)(1).2.3.3.19 Open Cycle Cooling Water System 2.3.3.19.1 Summary of Technical Information in the Application LRA Section 2.3.3.19 describes the OCCW system which consists of the mechanical draft cooling towers, nuclear service river water system, secondary services cooling water system, decay heat river system, screen wash and sluice system, screen house ventilation system, and river water pump lubrication system. The OCCW system is an auxiliary system designed to provide cooling water from the Susquehanna River to several plant components. The purpose of the OCCW system is to circulate cooling water from the river through both safety-related and nonsafety-related heat exchangers and back to the river. The OCCW system l accomplishes this by providing screened river water to the river water pump suctions and then circulating river water through the nuclear service closed cooling water heat exchangers, intermediate service closed cooling water coolers, decay heat service coolers, secondary services heat exchangers, and screen house ventilation equipment. The nuclear service river water, secondary services cooling water, screen wash and sluice, screen house ventilation, and river water pump lubrication systems are normally in operation. The decay heat river system is normally in operation during plant shutdown and is used part timeduring normal plant operation to augment the dilution of plant effluents. The decay heat river system will actuate automatically upon receipt of an engineered safeguards actuation signal and operate in the same way as for normal operation. Nuclear services river water will receive an automatic start signal when the engineered safeguards system actuates. During a loss of nuclear services river water, a cross connection with secondary services cooling water, requiring manual operator action, can provide cooling to the nuclear services river water heat loads.LRA Table 2.3.3-19 identifies the components subject to an AMR for the OCCW system by component type and intended function.2.3.3.19.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.19 and UFSAR Sections 9.6.1, 9.6.2, and 9.8.8.3 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions pursuant to 10 CFR 54.4(a). The staff then reviewed those componentsi that 2-64 drains, drain flowpaths, sumps, sump pumps, and discharge flowpaths from buildings and rooms. LRA Table 2.3.3-18 identifies the components subject to aging management review for the miscellaneous floor and equipment drain system by component type and intended function.i, 2.3.3.18.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concludes there is reasonable asslirance that the applicant has appropriately identified the MFED system components within the scope of license renewal, 'as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMRin accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.19 Open Cycle Cooling Water System 2.3.3.19.1 Summary of Technical Information in the Application LRA Section 2.3.3.19 describes the OCCW system which consists of the mechanical draft cooling towers, nuclear service river water system, secondary services cooling water system, decay heat river system, screen wash and sluice system, screen house ventilation system, and river pump lubrication system. The OCCW system is an auxiliary system designed to provide cooling water from the Susquehanna River to several plant components. The purpose of the OCCW system is to circulate cooling water from the river through both related and nonsafety-related heat exchangers and back to the river. The OCCW system l accomplishes this by providing screened river water to the river water pump suctions and circulating river water through the nuclear service closed cooling water heat exchangers, intermediate service closed cooling water coolers, decay heat service coolers, secondary heatexchangers, and screen house ventilation equipment. ' The nuclear service river water,' secondary services cooling water, screen wash and sluice, screen house ventilation, and river water pump lubrication systems are normally in operation. The decay heat river system is normally in operation during plant shutdown and is used part time during normal plant operation to augment the dilution of plant effluents. The decay heat river system will actuate automatically upon receipt of an engineered safeguards actuatio,n signal and operate in the same way as for normal operation. Nuclear services river water will receive an automatic start signal when the engineered. safeguards system actuates. During a loss of duclear services river water, a cross connection with secondary services cooling water, requiring manual operator action, can provide cooling to the nuclear services river water heat loads. LRA Table 2.3.3-19 identifies the components subject to an AMR for the OCCW system by component type and intended function. 2.3.3.19.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.19 and UFSAR Sections 9.6.1, 9.6.2, and 9.8.8.3 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with . I intended functions pursuant to 10 CFR 54.4( a). The staff then reviewed those componentsl that 2-64 the applicant identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR, in accordance with 10 CFR 54.21(a)(1). The staff's review of LRA Section 2.3.3.19 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results.In RAI 2.3.3.19-1, dated August 20, 2008, the staff noted that on license renewal drawing LR-302-203 the traveling water screens and automatic bar rakes are highlighted in green, indicating that they are within the scope of license renewal. The traveling water screens and debris bars (bar racks, not the automatic rakes) have a passive intended function of filter. On LRA page 2.3-139 in the last paragraph, the applicant stated that the OCCWS boundary begins at the intake screen and pump house bar racks. The staff noted that traveling water screens and debris bars have not been listed in LRA Table 2.3.3-19. The staff did not find the traveling water screens and debris bars included in LRA Section 2.4.8, Intake Screen and Pump House. The staff requested that the applicant provide additional information to justify the exclusion of the bar racks and traveling screens from the intended function of filter from LRA Table 2.3.3-19.In its response to the RAI, dated September 16, 2008, the applicant stated that the bar racks are passive components within the scope of license renewal with an intended function of filter. The applicant further stated that the bar racks are subject to an AMR and should have been included in LRA Table 2.3.3-19. The applicant further stated that there are bar grids, located at the outer most portion of the intake structure beyond the bar racks, that function to prevent large debris from entering the intake. The bar grids are also within the scope of license renewal with an intended function of filter, similar to the bar racks; however, the bar grids are not shown on license renewal drawing LR-302-203. The applicant explained that the traveling screens are also within the scope of license renewal with a filter intended function, but are active components and not subject to an AMR.The applicant amended the LRA by adding the component "Strainer Element (ISPH Bar Grids, ISPH Bar Racks)" with an intended function of filter to LRA Table 2.3.3-19 and by adding the same component type to LRA Table 3.3.2-19 with complete AMR results. In addition, the applicant amended the aging management programs list in LRA Section 3.3.2.1.19 to add AMP: "Structures Monitoring." The applicant also provided amended text for subsections System Operation, System Boundary, and System Intended Functions to LRA Section 2.3.3.19 for theOCCWS. The amended text reflected the addition of the bar grids and bar racks to components subject to an AMR for the system.On October 23, 2008, the staff conducted a conference call with the applicant to discuss their response to RAI 2.3.3.19-1. As a result of the teleconference, the applicant clarified that the correct dimensions of the bar grids is a 2-foot horizontal spacing and a 3.5-foot vertical spacing.Additionally, the applicant indicated that in the next to last paragraph on page 31 of 44 of its letter dated September 16, 2008, the word "in" was missing between the words "included" and "the." The sentence should read: "included in the OCCW System." Additionally, the applicant stated that for the strainer element bar grids and bar racks in revised Table 3.3.2.19 (see page 33 of 41 of September 16, 2008, letter) the word "internal" is incorrect and that the correct environment is"raw water external." The staff questioned whether the discussion section should be revised for Item 3.3.1- 79 in Table 3.3.1 based on the response to the RAI (see page 33 of 44 of September 16, 2008, letter). The applicant indicated that the discussion section for Item 3.3.1-79 in Table3.3.1 would be revised to reflect the structures monitoring program. The staff concurred with the applicant's proposed resolutions to the minor errors noted above.2-65 the applicant identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR, in accordance with 10 CFR 54.21(a)(1). The staffs review of LRA Section 2.3.3.19 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. In RAI 2.3.3.19-1, dated August 20,2008, the staff noted that on license renewal drawing LR-302-203 the traveling water screens and automatic bar rakes are highlighted in green, indicating that they are within the scope of license renewal. The traveling water screens and debris bars (bar racks, not the automatic rakes) have a passive intended function of filter. On LRA page 2.3-139 in the last paragraph, the applicant stated that the OCCWS boundary begins at the intake screen and pump house bar racks. The staff noted that traveling water screens and debris bars have not been listed in LRA Table 2.3.3-19. The staff did not find the traveling water screens and debris bars included in LRA Section 2.4.8, Intake Screen and Pump House. The staff requested that the applicant provide additional information to justify the exclusion of the bar racks and traveling screens from the intended function of filter from LRA Table 2.3.3-19. In its response to the RAI, dated September 16, 2008, the applicant stated that the bar racks are passive components within the scope of license renewal with an intended function of filter. The applicant further stated that the bar racks are subject to an AMR and should have been included in LRA Table 2.3.3-19. The applicant further stated that there are bar grids, located at the outer most portion of the intake structure beyond the bar racks, that function to prevent large debris from entering the intake. The bar grids are also within the scope of license renewal with an intended function of filter, similar to the bar racks; however, the bar grids are not shown on license renewal drawing LR-302-203. The applicant explained that the traveling screens are also within the scope of license renewal with a filter intended function, but are active components and not subject to an AMR. The applicant amended the LRA by adding the component "Strainer Element (ISPH Bar Grids, ISPH Bar Racks)" with an intended function of filter to LRA Table 2.3.3-19 and by adding the same component type to LRA Table 3.3.2-19 with completeAMR results. In addition, the applicant amended the aging management programs list in LRA Section 3.3.2.1.19 to add AMP: "Structures Monitoring." The applicant also provided amended text for subsections System Operation, System Boundary, and System Intended Functions to LRA Section 2.3.3.19 for the OCCWS. The amended text reflected the addition of the bar grids and bar racks to components subject to an AMR for the system. On October 23, 2008, the staff conducted a conference call with the applicant to discuss their response to RAI 2.3.3.19-1. As a result of the teleconference, the applicant clarified that the correct dimensions of the bar grids is a 2-foot horizontal spacing and a 3.5-foot vertical spacing. Additiona"y, the applicant indicated that in the next to last paragraph on page 31 of 44 of its letter dated September 16,2008, the word "in" was missing between the words "included" and "the." The sentence should read: "included in the OCCW System." Additiona"y, the applicant stated that for the strainer element bar grids and bar racks in revised Table 3.3.2.19 (see page 33 of 41 of September 16, 2008, letter) the word "internal" is incorrect and that the correct environment is "raw water external." The staff questioned whether the discussion section should be revised for Item 3.3.1-79 in Table 3.3.1 based on the response to the RAI (see page 33 of 44 of September 16,2008, letter). The applicant indicated that the discussion section for Item 3.3.1-79 in Table 3.3.1 would be revised to reflect the structures monitoring program. The staff concurred with the applicant's proposed resolutions to the minor errors noted above. 2-65 Based on its review, the staff finds the applicant's response to RAI 2.3.3.19-1 acceptable because the applicant added the intake structure's bar racks and bar grids to the scope of license renewal and identified them as subject to an AMR. The applicant added component "Strainer Element (ISPH Bar Grids, ISPH Bar Racks)" with an intended function of filter to LRA Tables 2.3.3-19 and 3.3.2-19. In addition, the applicant amended LRA Section 3.3.2.1.19 to add "Structures Monitoring" to the aging management programs list, and amended LRA Section 2.3.3.19 to address the addition of these components within the scope of license renewal. The staffs concern described in RAI 2.3.3.19-1 is resolved.In RAI 2.3.3.19-2, dated August 20, 2008, the staff noted that on license renewal drawing LR-302-202 there are two restricting orifices highlighted in red, indicating that they are within the scope of license renewal based on 10 CFR 54.4(a)(2) criteria; however, LRA Table 2.3.3-19 shows restricting orifices with a pressure boundary function only, indicting they are in scope based Ion 10 CFR 54.4(a)(1) or (a)(3) criteria. The appropriate function for (a)(2) components would be leakage boundary, but the components are not included in LRA Table 2.3.3-19 for restricting orifices!. The staff requested that the applicant provide additional information to justify the exclusion of the leakage boundary function for the restricting orifices from LRA Table 2.3.3-19. In its response to the RAI, dated September 16, 2008, the applicant stated the restricting orifices in the OCCWS perform both pressure and leakage boundary functions; however, the leakage boundary function was omitted from LRA Tables 2.3.3-19 and 3.3.2-19. The applicant amended the LRA by adding the intended function of leakage boundary to the component restricting orifices in LRA Tables 2.3.3-19 and 3.3.2-19 with complete aging management review results.Based on its review, the staff finds the applicant's response to RAI 2.3.3.19-2 acceptable because the applicant added the intended function "leakage boundary" for the component type restricting orifices to LRA Tables 2.3.3-19 and 3.3.2-19. The staff's concern described in RAI 2.3.3.19-2 is resolved.In RAI 2.3.3.19-3, dated November 24, 2008, the staff noted that on river water system license renewal drawing LR-302-202, a six-inch pipe is highlighted in red, indicating that the piping is within the scope of license renewal. The piping is shown to continue onto plant drawing 302-161 to a "Clarifier." However, the continuation arrow is not highlighted, indicating the downstream components were not included in the scope of license renewal, and continuation drawing 302-161 has not been provided. The staff needs to review the structures and components on this continuation drawing to verify that the applicant has properly included the components in scope and subject to an AMR as required by 10 CFR 54.21. The staff requested the applicant provide additional information for continuation drawing 302-161 identifying the structures and components within the scope of license renewal and subject to an AMR, or provide a basis for the exclusion ofthe structures and components on this drawing.In its response to the RAI, dated December 5, 2008, the applicant stated that the 30-inch diameter piping from the discharge header of the secondary services pumps on license renewaldrawing LR-302-202 runs underground to the heat exchanger vault located in the auxiliary building and that the 30-inch pipe is in scope for license renewal for 10 CFR 54.4(a)(2) criteria because it provides structural support to attached safety-related piping. The applicant stated that the attached six-inch branch piping is also buried and connects the 30-inch header to the clarifier located in the pretreatment building and that the branch six-inch piping and the clarifier do not perform an intended function required to be included in the scope of license renewal. The applicant stated that the six-inch branch piping from the 30-inch header should have been colored black on license renewal drawing LR-302-202 to indicate that it is not in scope of license renewal.2-66 Based on its review, the staff finds the applicant's response to RAI 2.3.3.19-1 acceptable because the applicant added the intake structure's bar racks and bar grids to the scope of license renewal and identified them as subject to an AMR. The applicant added component "Strainer Element (ISPH Bar Grids, ISPH Bar Racks)" with an intended function of filter to LRA Tables 2.3.3-19 and 3.3.2-19. In addition, the applicant amended LRA Section 3.3.2.1.19 to add "Structures Monitoring" to the aging management programs list, and amended LRA Section 2.3.3.19 to address the addition of these components within the scope of license renewal. The staff's concern described in RAI 2.3.3.19-1 is resolved. In RAI 2.3.3.19-2, dated August 20, 2008, the staff noted that on license renewal drawing LR-302-202 there are two restricting orifices highlighted in red, indicating that they are within the scqpe of license renewal based on 10 CFR 54.4(a)(2) criteria; however, LRA Table 2.3.3-19 shows restricting orifices with a pressure boundary function only, indicting they are in scope basedilon 10 CFR 54.4(a)(1) or (a)(3) criteria. The appropriate function for (a)(2) components would be leakage boundary, but the components are not included in LRA Table 2.3.3-19 for restricting orifices i[ The staff requested that the applicant provide additional information to justify the exclusion of leakage boundary function for the restricting orifices from LRA Table 2.3.3-19. . In its response to the RAI, dated September 16, 2008, the applicant stated the restricting orifices in the OCCWS perform both pressure and leakage boundary functions; however, the leakage boundary function was omitted from LRA Tables 2.3.3-19 and 3.3.2-19. The applicant amended the LRA by adding the intended function of leakage boundary to the component restricting orifices in LRA Tables 2.3.3-19 and 3.3.2-19 with complete aging management review results. Based on its review, the staff finds the applicant's response to RAI 2.3.3.19-2 acceptable because the applicant added the intended function "leakage boundary" for the component type restricting orifices to LRA Tables 2.3.3-19 and 3.3.2-19. The staff's concern described in RAI2.3.3.19-2 is resolved. In RAI 2.3.3.19-3, dated November 24, 2008, the staff noted that on river water system license renewal drawing LR-302-202, a six-inch pipe is highlighted in red, indicating that the piping is within the scope of license renewal. The piping is shown to continue onto plant drawing 161 to a "Clarifier." However, the continuation arrow is not highlighted, indicating the downstream components were not included in the scope of license renewal, and continuation drawing 3q2-161 has not been provided. The staff needs to review the structures and components on this . continuation drawing to verify that the applicant has properly included the components in scope and subject to an AMR as required by 10 CFR 54.21. The staff requested the applicant provide additional information for continuation drawing 302-161 identifying the structures and components within the scope of license renewal and subject to an AMR, or provide a basis for the exclusion of the structures and components on this drawing. . In its response to the RAI, dated December 5,2008, the applicant stated that the 30-inch diameter piping from the discharge header of the secondary services pumps on license renewal drawing LR-302-202 runs underground to the heat exchanger vault located in the auxiliary building and that the 30-inch pipe is in scope for license renewal for 10 CFR 54.4(a)(2) criteria because it provides structural support to attached safety-related piping. The applicant stated that the attached six-inch branch piping is also buried and connects the 30-inch header to the clarifier located in the pretreatment building and that the branch six-inch piping and the clarifier do not perform an intended function required to be included in the scope of license renewal. The applicant stated that the six-inch branch piping from the 30-inch header should have been c:olored black on license renewal drawing LR-302-202 to indicate that it is not in scope of license renewal. 2-66 The applicant stated that components shown on continuation drawing 302-161 are also not included in the scope of license renewal.Based on its review, the staff found the applicant's response to RAI 2.3.3.19-3 acceptable because the applicant clarified that the six-inch branch piping and the clarifier do not perform an intended function for license renewal and should have been colored black. The staff's concern described in RAI 2.3.3.19-3 is resolved.2.3.3.19.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the OCCW system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.20 Radiation Monitoring System 2.3.3.20.1 Summary of Technical Information in the Application LRA Section 2.3.3.20 describes the radiation monitoring (RM) system which consists of the following plant systems: radiation monitoring and sampling system and post accident monitoring system. The RM system is an auxiliary system designed to detect, indicate, annunciate, and record radiation levels at selected locations inside and outside the plant. It also provides interlock signals to support intended functions on high radiation level detection. The RM system accomplishes this through area, atmospheric, and liquid radiation monitors.Area monitoring consists of twenty-four channels which perform personnel, process, and effluent monitoring functions. Area monitors are single, self-contained detector units with no associatedsampling or detection piping and components. Area monitors detect radiation levels inside the reactor building, auxiliary building, control tower, and fuel handling building. RM-G-9 fuel handling building area monitor is nonsafety-related and provides an isolation signal for the fuel handling building ventilation system. Area monitors also monitor once through steam generators, reactor coolant, reactor coolant pump seal return, and reactor coolant drain tank pump discharge. RM-G-9 is a nonsafety-related area monitor that supports an intended function of isolating the fuel handling building ventilation system. It provides an interlock signal on high radiation level indication. The other area monitors do not support intended functions and their failure would not prevent safety-related components or systems from performing their intended functions. Atmospheric monitoring consists of fifteen channels which provide effluent monitoring, emergency release monitoring, and in-plant air monitoring. Channels are located inside and outside the plant.Atmospheric monitors detect radiation levels in the control tower air intake, reactor building air sample line, fuel handling building exhaust ventilation duct, condenser vacuum pump exhaust, waste gas discharge, auxiliary and fuel handling building exhaust, reactor building purge exhaust, radiochemical laboratory, fuel handling building emergency safety features ventilation system exhaust, chemical cleaning building ventilation exhaust, waste handling and packing facility exhaust, and the respirator cleaning and laundry maintenance (RLM) facility exhaust.Atmospheric monitors have associated sampling and detection piping and components. The control tower air intake channel (RM-A1) is nonsafety-related and supports an intended function of maintaining control room habitability by placing the control room ventilation system in recirculation mode. The fuel handling building exhaust ventilation duct channel (RM-A-4) and the 2-67 The applicant stated that components shown on continuation drawing 302-161 are also not included in the scope of license renewal. Based on its review, the staff found the applicant's response to RAI 2.3.3.19-3 acceptable because the applicant clarified that the six-inch branch piping and the clarifier do not perform an intended function for license renewal and should have been colored black. The staff's concern described in RAI 2.3.3.19-3 is resolved. 2.3.3.19.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the OCCW system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.20 Radiation Monitoring System 2.3.3.20.1 Summary of Technical Information in the Application LRA Section 2.3.3.20 describes the radiation monitoring (RM) system which consists of the following plant systems: radiation monitoring and sampling system and post accident monitoring system. The RM system is an auxiliary system designed to detect, indicate, annunciate, and record radiation levels at selected locations inside and outside the plant. It also provides interlock signals to support intended functions on high radiation level detection. The RM system accomplishes this through area, atmospheric, and liquid radiation monitors. Area monitoring consists of twenty-four channels which perform personnel, process, and effluent monitoring functions. Area monitors are single, self-contained detector units with no associated sampling or detection piping and components. Area monitors detect radiation levels inside the reactor building, auxiliary building, control tower, and fuel. handling building. RM-G-9 fuel handling building area monitor is nonsafety-related and provides an isolation signal for the fuel handling building ventilation system. Area monitors also monitor once through steam generators, reactor cqolant, reactor coolant pump seal return, and reactor coolant drain tank pump discharge. RM-G-, 9 is a nonsafety-related area monitor that supports an intended function of isolating the fuel handling building ventilation system. It provides an interlock signal on high radiation level indication. The other area monitors do not support intended functions and their failure would not prevent safety-related components or systems from performing their intended functions. Atmospheric monitoring consists of fifteen channels which provide effluent monitoring, emergency . release monitoring, and in-plant air monitoring. Channels are located inside and outside the plant. Atmospheric monitors detect radiation levels in the control tower air intake, reactor building air sample line, fuel handling building exhaust ventilation duct, condenser vacuum pump exhaust, waste gas discharge, auxiliary and fuel handling building exhaust, reactor building purge exhaust, radiochemical laboratory, fuel handling building emergency safety features ventilation system exhaust, chemical cleaning building ventilation exhaust, waste handling and packing facility exhaust, and the respirator cleaning and laundry maintenance (RLM) facility exhaust. Atmospheric monitors have associated sampling and detection piping and components. The control tower air intake channel (RM-A 1) is nonsafety-related and supports an intended function of maintaining control room habitability by placing the control room ventilation system in recirculation mode. The fuel handling building exhaust ventilation duct channel (RM-A-4) and the 2-67 reactor building purge exhaust channel (RM-A-9) are nonsafety-related and sense process conditions and generate signals to isolate ventilation systems. The fuel handling building ESF ventilation system exhaust channel (RM-A-14) is nonsafety-related and supports and intendedfunction of removing radioactive material from the atmosphere of confined spaces outside primary containment by isolating the ventilation system. The other atmospheric monitors do not support intended functions and their failure would not prevent safety-related components or systems from performing their intended functions. Liquid monitoring consists of nine liquid monitors which provide effluent monitoring, leak detection, and monitoring of the reactor coolant system activity.Liquid monitors detect radiation levels of closed cooling loops, spent fuel pool water, reactor coolant letdown, liquid wastewater prior to dilution by the mechanical draft cooling tower basin, discharge to the river, and industrial waste treatment discharge. Liquid monitors and associated sampling and detection piping and components are not included in the scope of this system and are evaluated with the license renewal system associated with the process fluid (i.e., closed cydle cooling water system, makeup and purification system, and spent fuel cooling system). Post-accident radiation monitoring consists of high-range effluent monitors for extended ranges to area radiation monitors and high-range containment radiation monitors to monitor containment radiation levels during and following a postulated accident. The high range containment radiation monitors perform an intended function and are in the scope of license renewal.LRA Table 2.3.3-20 identifies the components subject to an AMR for the RM system by component type and intended function.2.3.3.20.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.20 and UFSAR Sections 4.2.3.8, 5.3.2, 7.3.2.2, 7.4.2.1, 9.1.2, 9.2.2.5, 9.3.2.5, 9.4.6, 9.6.2.1, 9.8.1.5, 9.8.2, 9.8.3, 10.3.3.2, 11.2.1.3, 11.4, and 14.2.2.1 as well as LRA Tables 7.3 2 and 7.3-3 using the evaluation methodology described in SER Section2.3 and the guidance in SRP-LR Section 2.3.During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions pursuant to 10 CFR 54.4(a). The staff then reviewed those components that the applicant identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR, in accordance with 10 CFR 54.21(a)(1). The staff's review of LRA Section 2.3.3.20 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results.In RAI 2.3.3.20-1, dated August 20, 2008, the staff noted that on license renewal drawing LR-302-833, sheet 1, an isokinetic nozzle (REAl 4) is highlighted in green, indicating it is within the scope of license renewal for 10 CFR 54.4(a)(1). The nozzle is associated with the radiation monitor RM-A14 and has an intended function of pressure boundary and direct flow. LRA Table 2.3.3-20 does not show the nozzle as a component with an intended function of pressure boundary or direct flow. The staff requested that the applicant provide additional information to justify the exclusion of the isokinetic nozzle from LRA Table 2.3.3-20.In its response to the RAI, dated September 16, 2008, the applicant stated that the isokinetic nozzle highlighted in green on license renewal drawing LR-302-833, is in the scope of license renewal with intended functions of direct flow and pressure boundary; however, it was omitted 2-68 reactor building purge exhaust channel (RM-A-9) are nonsafety-related and sense process . conditions arid generate signals to isolate ventilation systems. The fuel handling building ESF ventilation system exhaust channel (RM-A-14) is nonsafety-related and supports and intended function of removing radioactive material from the atmosphere of confined spaces outside primary containment by isolating the ventilation system. The other atmospheric monitors do not support intended functions and their failure would not prevent safety-related components or from performing their intended functions. Liquid monitoring consists of nine liquid monitors which provide effluent monitoring, leak detection, and monitoring of the reactor coolant system activity. Liquid monitors detect radiation levels of closed cooling loops, spent fuel pool water, reactor coolant letdown, liquid wastewater prior to dilution by the mechanical draft cooling tower basin, discharge to the river, and industrial waste treatment discharge. I Liquid monitors and associated sampling and detection piping and components are not included in the scope of this system and are evaluated with the license renewal system associated with the process fluid (Le., closed cyCle cooling water system, makeup and purification system, and spent fuel cooling system). Post-accident radiation monitoring consists of high-range effluent monitors for extended ranges to area radiation monitors and high-range containment radiation monitors to monitor containment radiation levels during and following a postulated accident. The high range containment radiation monitors perform an intended function and are in the scope of license renewal. .. LRA Table 2.3.3-20 identifies the components subject to an AMR for the RM system by component type and intended function. 2.3.3.20.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.20 and UFSAR Sections 4.2.3.8, 5.3.2, 7.3.2.2, 7.4.2.1, 9.1.2, 9.2.2.5, 9.3.2.5, 9.4.6, 9.6.2.1, 9.8.1.5, 9.8.2, 9.8.3, 10.3.3.2, 11.2.1.3, 11.4, and 14.2.2.1 as . . II well as LRATables 7.3 2 and 7.3-3 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions 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 the applicant has not omitted any passive and. long-lived components subject to an AMR, in accordance with 10 CFR 54.21(a)(1). The staff's review of LRA Section 2.3.3.20 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. In RAI 2.3.3.20-1, dated August 20,2008, the staff noted that on license renewal drawing LR-302-833, sheet 1, an isokinetic nozzle (REA 14) is highlighted in green, indicating it is within the scope of license renewal for 10 CFR 54.4(a)(1). The nozzle is associated with the radiation monitor A 14 and has an intended function of pressure boundary and direct flow. LRA Table 2.3.3-20 does not show the nozzle as a component with an intended function of pressure boundary or direct flow. The staff requested that the applicant provide additional information to justify the of the isokinetic nozzle from LRA Table 2.3.3-20. In its response to the RAI, dated September 16, 2008, the applicant stated that the isokinetic nozzle highlighted in green on license renewal drawing LR-302-833, is in the scope of liceQse renewal with intended functions of direct flow and pressure boundary; however, it was omitted 2-68 from LRA Tables 2.3.3-20 and 3.3.2-20. Also in its response, the applicant amended the LRA byadding the component "Nozzle (Isokinetic Nozzle)" with an intended function of direct flow and pressure boundary to LRA Tables 2.3.3-20 and 3.3.2-20 with complete AMR results.Based on its review, the staff finds the applicant's response to RAI 2.3.3.20-1 acceptable because the applicant added the component "Nozzle (Isokinetic Nozzle)" with intended functions of direct flow and pressure boundary to LRA Tables 2.3.3-20 and 3.3.2-20. The staffs concern described in RAI 2.3.3.20-1 is resolved.2.3.3.20.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the radiation monitoring system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.21 Radwaste System 2.3.3.21.1 Summary of Technical Information in the Application LRA Section 2.3.3.21 describes the radwaste system as a normally operating liquid, solid, and gaseous radioactive waste management system. The radwaste system consists of several plant systems including the gaseous Waste disposal system, the liquid radwaste disposal system, the solid radwaste disposal system, the processed water system, and the incore detector disposal system.The purpose of the radwaste system is to manage radioactive waste produced as a result of plant operation. The radwaste system accomplishes this by collecting, processing, and preparing for disposal, potentially radioactive liquid, gaseous, and solid wastes. The radwaste system is designed and constructed to meet or exceed the applicable federal regulations for the containment, control, and release or disposal of radioactive liquids, gases, and solids generated as a result of normal and emergency operation of the plant.The radwaste system includes reactor building isolation valves and piping to assure that radioactive material is not inadvertently transferred out of the reactor building, and, it includes valves for, or associated with, flowpaths required for safe shutdown. The radwaste system collects, contains, and suppresses steam relief from the RCS pressurizer PORV and code safety valves. LRA Table 2.3.3-21 identifies the components subject to an AMR for the radwaste system by component type and intended function.2.3.3.21.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concludes there is reasonable assurance that the applicant has appropriately identified the radwaste system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21 (a)(1).2-69 froin LRA Tables 2.3.3-20 and 3.3.2-20. Also in its response, the applicant amended the LRA by adding the component "Nozzle (Isokinetic Nozzle)" with an in.tended function of direct flow and pressure boundary to LRA Tables 2.3.3-20 and 3.3.2-20 with complete AMR results. Based on its review, the staff finds the applicant's response to RAI 2.3.3.20-1 acceptable because the applicant added the component "Nozzle (Isokinetic Nozzle)" with intended functions of direct flow and pressure boundary to LRA Tables 2.3.3-20 and 3.3.2-20. The staffs concern described in RAI 2.3.3.20-1 is resolved . . 2.3.3.20.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the radiation monitoring system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.21 Radwaste System 2.3.3.21.1 Summary of Technical Information in the Application LRA Section 2.3.3.21 describes the radwaste system as a normally operating liquid, solid, and gaseous radioactive waste management system. The radwaste system consists of several plant systems including the gaseous waste disposal system, the liquid radwaste disposal system, the solid radwaste disposal system, the processed water system, and the incore detector disposal system. The purpose of the radwaste system is to manage radioactive waste produced as a result of plant operation. The radwaste system accomplishes this by collecting, processing, and preparing for disposal, potentially radioactive liquid,gaseous, and solid wastes. The radwaste system is designed and constructed to meet or exceed the applicable federal regulations for the containment, control, and release or disposal of radioactive liquids, gases, and solids generated as a result of normal and emergency operation of the plant. The radwaste system includes reactor building isolation valves and piping to assure that radioactive material is not inadvertently transferred out of the reactor building, and, it includes valves for, or associated with, flowpaths required for safe shutdown. The radwaste*system collects, contains, and suppresses steam relief from the RCS pressurizer PORV and code safety valves. LRA Table 2.3.3-21 identifies the components subject to an AMR for the radwaste system by component type and intended function. 2.3.3.21.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concludes there is reasonable assurance that the applicant has appropriately identified the radwaste system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2-69 2.3.3.22 Service Building Chilled Water System 2.3.3.22.1 Summary of Technical Information in the Application LRA Section 2.3.3.22 describes the service building chilled water (SBCW) system. The purpose of the SBCW for license renewal is to maintain leakage boundary integrity to preclude system interactions. For this reason, this system's pressure retaining components located in proximity to other components performing safety-related functions have been included in the scope of license renewal.The purpose of the service building chilled water system is to provide heat removal for the service building ventilation, which is not in scope for license renewal. The service building chilled watersystem accomplishes this by supplying cooling water for the service building air handling units.The system is normally in operation. The intended function of the service building chilled water system within the scope of license renewal is to resist nonsafety-related SSC failure.LRA Table 2.3.3-22 identifies the components subject to an AMR for the service building chilled water system by component type and intended function.2.3.3.22.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.22 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 has not omitted from the scope of license renewal any components with intended functions pursuant to 10 CFR 54.4(a). The staff then reviewed those components that the applicant identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR, in accordance with 10 CFR 54.21(a)(1). The staffs review of LRA Section 2.3.3.22 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results.In RAI 2.3.3.22-1, dated August 20, 2008, the staff noted that on license renewal drawing LR-302-846, level indicator LI-1 007 is highlighted in red, indicating that it is within the scope of license renewal based on 10 CFR 54.4(a)(2) criteria. This component type typically includes a sight glass, which would have a leakage boundary function. Sight glass is not listed in LRA Tables 2.3.13-22 and 3.3.2-22 as a component type with a leakage boundary function. The staff requested that the applicant provide additional information to justify the exclusion of the sight glass from LRA Tables 2.3.3-22 and 3.3.2-22.In its response to the RAI, dated September 16, 2008, the applicant stated that the sight glass, LI-1007, shown in red on license renewal drawing LR-302-846, is in the scope of license renewal with an intended function of leakage boundary; however, it was omitted from LRA Tables 2.3.3-22 and 3.3.2-22. The applicant amended the LRA by adding the component "sight glass" with I'an intended function of leakage boundary to LRA Tables 2.3.3-22 and 3.3.2-22 with complete AMR results, and adding the material "glass" to LRA Section 3.3.2.1.22. 2-70 2.3.3.22 Service Building Chilled Water System 2.3.3.22.1 Summary of Technical Information in the Application LRA Section 2.3.3.22 describes the service building chilled water (SBCW) system. The purpose of the SBCW for license renewal is to maintain leakage boundary integrity to preclude system interactions. For this reason, this system's pressure retaining components located in proximity to other components performing safety-related functions have been included in the scope of license renewal. The purpose of the service building chilled water system is to provide heat removal for the service building ventilation, which is not in scope for license renewal. The service building chilled water system accomplishes this by supplying cooling water for the service building air handling units. The system is normally in operation. The intended function of the service building chilled water system within the scope of license renewal is to resist nonsafety-related SSC failure. LRA Table 2.3.3-22 identifies the components subject to an AMR for the service building chilled water system by component type and intended function. 2.3.3.22.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.22 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 ClPplicant has not omitted from the scope of license renewal any components with intended functions pursuant to 10 CFR 54.4(a). The staff then reviewed those components that the applicant identified as within the scope of license renewal to verify that the applicant has n0t 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 2.3.3.22 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. In RAI 2.3.3.22-1, dated August 20,2008, the staff noted that on license renewal drawing LR-302-846, level indicator U-1 007 is highlighted in red, indicating that it is within the scope of license renewal based on 10 CFR 54.4(a)(2) criteria. This component type typically includes a glass, which would have a leakage boundary function. Sight glass is not listed in LRA Tables 2.3.;3-22 and 3.3.2-22 as a component type with a leakage boundary function. The staff requested that the applicant provide additional information to justify the exclusion of the sight glass from LRA Tables 2.3.3-22 and 3.3.2-22. In its response to the RAI, dated September 16, 2008, the applicant stated that the sight 9113ss, U-1007, shown in red on license renewal drawing LR-302-846, is in the scope of license renewal with an intended function of leakage boundary; however, it was omitted from LRA Tables 2.3.3-22 and 3.3.2-22. The applicant amended the LRA by adding the component "sight glass" with iian intended function of leakage boundary to LRA Tables 2.3.3-22 and 3.3.2-22 with complete AMR results, and adding the material "glass" to LRA Section 3.3.2.1.22. 2-70 Based on its review, the staff finds the applicant's response to RAI 2.3.3.22-1 acceptable because the applicant added the component "sight glass" with an intended function of leakage boundary to LRA Tables 2.3.3-22 and 3.3.2-22, and added the material "glass" to LRA Section 3.3.2.1.22. The staff's concern described in RAI 2.3.3.22-1 is resolved.2.3.3.22.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the service building chilled water system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.23 Spent Fuel Cooling System 2.3.3.23.1 Summary of Technical Information in the Application LRA Section 2.3.3.23 describes the spent fuel cooling (SFC) system which is a mechanical, safety-related, normally operating system designed to remove decay heat from the spent fuel stored in the spent fuel pools. The SFC system is capable of maintaining spent fuel pool temperatures within design limits. The purpose of the SFC system is to remove decay heat from the spent fuel stored in the pools. The SFC system accomplishes this by forced circulation of spent fuel pool water through coolers. The SFC system operation is initiated by manual control for spent fuel cooling functions. Secondary functions are controlled via local manipulation of valves and control equipment. LRA Table 2.3.3-23 identifies the components subject to an AMR for the SFC system by component type and intended function.2.3.3.23.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the SFC system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.24 Station Blackout and UPS Diesel Generator System 2.3.3.24.1 Summary of Technical Information in the Application LRA Section 2.3.3.24 describes the SBO and uninterruptible power supply (UPS) diesel generator systems which consist of the following plant systems: SBO diesel and support systems (mechanical) and UPS diesel (mechanical). The SBO system is an auxiliary system designed to supply electrical power to key plant components during a SBO event. These include the mechanical portions of the UPS diesel system. Only electrical components of the UPS are required to perform an intended function, which is to provide power to trip signals during an ATWS event. Those electrical components are evaluated with the 120 V vital power systems.The SBO system is a mechanical system designed to provide the motive force for generating electrical power for key plant components during a SBO event. The SBO system accomplishes this by utilizing diesel engines to rotate electric generators attached to the diesel engines. Fuel supply, air supply, and cooling water support SBO diesel engine operation. LRA Table 2.3.3-24 2-71 Based on its review, the staff finds the applicant's response to RAI 2.3.3.22-1 acceptable because the applicant added the component "sight glass" with an intended function of leakage boundary to LRA Tables 2.3.3-22 and 3.3.2-22, and added the material "glass" to LRA Section 3.3.2.1.22. The staff's concern described in RAI 2.3.3.22-1 is resolved. 2.3.3.22.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the service building chilled water system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21 (a)(1). 2.3.3.23 Spent Fuel Cooling System 2.3.3.23.1 Summary of Technical Information in the Application LRA Section 2.3.3.23 describes the spent fuel cooling (SFC) system which is a mechanical, safety-related, normally operating system designed to remove decay heat from the spent fuel stored in the spent fuel pools. The SFC system is capable of maintaining spent fuel pool temperatures within design limits. The purpose of the SFC system is to remove decay heat from the spent fuel stored in the pools. The SFC system accomplishes this by forced circulation of spent fuel pool water through coolers. The SFC system operation is initiated by manual control for spent fuel cooling functions. Secondary functions are controlled via local manipulation of valves anq control equipment. LRA Table 2.3.3-23 identifies the components subject to an AMR for the SFC system by component type and intended function. 2.3.3.23.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the SFC system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.24 Station Blackout and UPS Diesel Generator System 2.3.3.24.1 Summary of Technical Information in the Application LRA Section 2.3.3.24 describes the SBO and uninterruptible power supply (UPS) diesel generator systems which consist of the following plant systems: SBO diesel and support systems (mechanical) and UPS diesel (mechanical). The SBO system is an auxiliary system designed to supply electrical power to key plant components during a SBO event. These include the mechanical portions of the UPS diesel system. Only electrical components of the UPS are required to perform an intended function, which is to provide power to trip signals during an A TWS event. Those electrical components are evaluated with the 120 V vital power systems. The SBO system is a mechanical system designed to provide the motive force for generating electrical power for key plant components during a SBO event. The SBO system accomplishes this by utilizing diesel engines to rotate electric generators attached to the diesel engines. Fuel supply, air supply, and cooling water support SBO diesel engine operation. LRA Table 2.3.3-24 2-71 identifies the components subject to an AMR for the SBO and UPS diesel generator systems by component type and intended function.2.3.3.24.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the SBO system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.3.25 Water Treatment and Distribution System 2,3.3.25.1 Summary of Technical Information in the Application LRA Section 2.3.3.25 describes the water treatment and distribution (WTD) system which consists of the following plant systems: water pretreatment system, cycle makeup demineralizer system, demineralized water system, domestic water system, reclaimed water system, filtered water system, river water biocide system, and domestic plumbing and drainage systems.The purpose of the WTD system is to provide storage and supply of domestic, demineralized, filtered, and well water for various uses throughout the site. The WTD system accomplishes this by utilizing filters, demineralizers, tanks, piping, and pumps to store, process, and transfer the water to the end-use systems.LRA Table 2.3.3-25 identifies the components subject to an AMR for the WTD system by component type and intended function.2.3.3.25.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.25 and UFSAR Sections 9.2.1, 9.6.1, 10.4.1, 10.4.2, ,11.2, and LRA Table 5.3-2 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions 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 the applicant has not 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 2.3.3.25 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results.In RAI 2.3.3.25-1, dated August 20, 2008, staff noted that on license renewal drawing LR-302-162 a vacuum degasifier tank is highlighted in red, indicating that it is within the scope of license renewal based on 10 CFR 54.4(a)(2) criteria. This component type should have a leakage boundary function. LRA Table 2.3.3-25 includes tank as a component type and itemizes which tanks are included. However, the table does not show the vacuum degasifier tank as a component subject to an AMR. The staff requested that the applicant provide additional information to justify the exclusion of the vacuum degasifier tank from LRA Table 2.3.3-25.2-72 identifies the components subject to an AMR for the SBO and UPS diesel generator systems by component type and intended function. 2.3.3.24.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the SBO system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). . . 2.3.3.25 Water Treatment and Distribution System 2.3.3.25.1 Summary of Technical Information in the Application LRA Section 2.3.3.25 describes the water treatment and distribution (WTD) system which consists of the following plant systems: water pretreatment system, cycle makeup demineri3lizer system, demineralized water system, domestic water system, reclaimed water system, filtered water system, river water biocide system, and domestic plumbing and drainage systems. The purpose of the WTD system is to provide storage and supply of domestic, demineralized, filtered, and well water for various uses throughout the site. The WTD system accomplishes this by utilizing filters, demineralizers, tanks, piping, and pumps to store, process, and transfer the water to the end-use systems. LRA Table 2.3.3-25 identifies the components subject to an AMR for the WTD system by componenttype and intended function. 2.3.3.25.2 Staff Evaluation The staff reviewed LRA Section 2.3:3.25 and UFSAR Sections 9.2.1, 9.6.1, 10.4.1, 10.4.2, ,,11.2, and LRA Table 5.3-2 using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any components with intended functions 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 the applicant has not omitted any passive and long-lived components subject to an AMR, in accordance with ' 10 CFR 54.21(a)(1). The staff's review of LRA Section 2.3.3.25 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. In RAI 2.3.3.25-1, dated August 20,2008, staff noted that on license renewal drawing LR-302-162 a vacuum degasifier tank is highlighted in red, indicating that it is within the scope of license renewal based on 10 CFR 54.4(a)(2) criteria. This component type should have a leakage boundary function. LRA Table 2.3.3-25 includes tank as a component type and itemizes which tanks are included. However, the table does not show the vacuum degasifier tank as a component subject to an AMR. The staff requested that the applicant provide additional information to justify the exclusion of the vacuum degasifier tank from LRA Table 2.3.3-25. 2-72 In its response to the RAI, dated September 16, 2008, the applicant stated that the license renewal drawing LR-302-162 highlighting is correct showing the vacuum degasifier tank in the scope of license renewal with an intended function of leakage boundary; however, this tank was omitted from LRA Tables 2.3.3-25 and 3.3.2-25. The applicant also stated the degasifier booster pumps highlighted on license renewal drawing LR-302-162 are within the scope of license renewal and have an intended function of leakage boundary, but the pumps were also omitted from LRA Tables 2.3.3-25 and 3.3.2-25. The applicant amended the LRA by adding the components "Pump Casing (Degasifier Booster Pumps)" and "Tanks (Vacuum Degasifier Tank)" with intended functions of leakage boundary to LRA Tables 2.3.3-25 and 3.3.2-25 with complete AMR results.Based on its review, the staff finds the applicant's response to RAI 2.3.3.25-1 acceptable because the applicant added the component "Pump Casing (Degasifier Booster Pumps)" and "Tanks (Vacuum Degasifier Tank)" to LRA Tables 2:3.3-25 and 3.3.2-25. The staff's concern described in RAI 2.3.3.25-1 is resolved.2.3.3.25.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the water treatment and distribution system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the systemcomponents subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).

2.3.4 Steam

and Power Conversion Systems LRA Section 2.3.4 identifies the steam and power conversion systems SCs 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: " Condensate System* Condensers and Air Removal System* Emergency Feedwater System* Extraction Steam System* Feedwater System* Main Generator and Auxiliary Systems" Main Steam System* Steam Turbine and Auxiliary Systems 2.3.4.1 Condensate System 2.3.4.1.1 Summary of Technical Information in the Application LRA Section 2.3.4.1 describes the condensate system which is a normally operating secondary side water system that consists of the following plant systems: main condensate system, powdex condensate polishing system, condensate seal water system, and condensate chemical feed 2-73 In its response to the RAI, dated September 16,2008, the applicant stated that the license renewal drawing LR-302-162 highlighting is correct showing the vacuum degasifier tank in the scope of license renewal with an intended function of leakage boundary; however, this tank was omitted from LRA Tables 2.3.3-25 and 3.3.2-25. The applicant also stated the degasifier booster pumps highlighted on license renewal drawing LR-302-162 are within the scope of license renewal and have an intended function of leakage boundary, but the pumps were also omitted from LRA Tables 2.3.3-25 and 3.3.2-25. The applicant amended the LRA by adding the components "Pump Casing (Degasifier Booster Pumps)" and "Tanks (Vacuum Degasifier Tank)" with intended functions of leakage boundary to LRA Tables 2.3.3-25 and 3.3.2-25 with complete AMRresults. Based on its review, the staff finds the applicant's response to RAI 2.3.3.25-1 acceptable because the applicant added the component "Pump Casing (Degasifier Booster Pumps)" and "Tanks (Vacuum Degasifier Tank)" to LRA Tables 2:3.3-25 and 3.3.2-25. The staff's concern described in RAI2.3.3.25-1

s resolved.

2.3.3.25.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the water treatment and distribution system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).

2.3.4 Steam

and Power Conversion Systems LRA Section 2.3.4 identifies the steam and power conversion systems SCs 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:

  • Condensate System
  • Condensers and Air Removal System
  • Emergency Feedwater System
  • Extraction Steam System
  • Feedwater System
  • Main Generator and Auxiliary Systems
  • Main Steam System
  • Steam Turbine and Auxiliary Systems 2.3.4.1 Condensate System 2.3.4.1.1 Summary of Technical Information in the Application LRA Section 2.3.4.1 describes the condensate system which is a normally operating secondary side water system that consists of the following plant systems: main condensate system, powdex condensate polishing system, condensate seal water system, and condensate chemical feed 2-73 system. The condensate system has several interfaces with other systems that are not within the license renewal boundary of the condensate system.The purpose of the condensate system is to deliver water to the main and emergency feedwater pumps. During normal plant conditions the condensate system delivers deaerated water from the main condenser hotwell to the suction header of the feedwater system, such that the net positive suction head requirements of the main feedwater pumps and the water purity requirements

ýof the OTSGs are met. During abnormal conditions the condensate system provides water to the i emergency feedwater pumps from condensate storage tanks, the primary water supply for these pumps. The main condenser hotwell can also be aligned to the suction of the emergency 1 feedwater pumps as an alternate water supply. The condensate system design provides alternate flow paths from each of these water sources to the emergency feedwater pumps, satisfyingl' requirements for plant safe shutdown during a fire.During a station blackout event, the inventory of the condensate storage tanks is used for decay heat removal. The condensate system includes the powdex condensate polishers that function to establish and maintain the required quality-of the feedwater delivered to the OTSGs. The seal water function of the condensate system prevents air from entering the main condenser by placing a water seal on valves and pumps subject to condenser vacuum. Due to its interfaces with the main condenser, the condensate system itself functions as part of the pressure boundary for main condenser vacuum. The condensate system also provides chemical treatment of secondary side water to maintain feedwater pH, feedwater oxygen, and second stage high pressure heater pH within design limits. Additionally, the condensate system serves as a water supply to condenser expansion joints, turbine exhaust hood spray, reactor coolant bleed tanks, and the CCCW System.LRA Table 2.3.4-1 identifies the components subject to an AMR for the condensate system by component type and intended function.2.3.4.1.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concludes there is reasonable assurance that the applicant has appropriately identified the condensate system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21 (a)(1).2.3.4.2 Condensers and Air Removal System 2.3.4.2.1 Summary of Technical Information in the Application LRA Section 2.3.4.2 describes the condensers & air removal system which is a normally operating system designed primarily to condense and deaerate steam from the main turbine and the main feedwater pump turbines. The condensers & air removal system consists of several plant systems including the main condenser, main condenser air removal system, auxiliary condensers, and auxiliary condensers air removal system.The purpose of the main condenser and auxiliary condenser portions of the system is to recover water used in the steam cycle by condensing and deaerating unused steam. The system accomplishes this by transferring heat to the circulating water system (which is within the tube 2-74 system. The condensate system has several interfaces with other systems that are not within the license renewal boundary of the condensate system. :1 II The purpose of the condensate system is to deliver water to the main and emergency feed""ater pumps. During normal plant conditions the condensate system delivers deaerated water fro:rn the main condenser hotwell to the suction header of the feedwater system, such that the net pdsitive suction head requirements of the main feedwater pumps and the water purity requirements I:Of the OTSGs are met. During abnormal conditions the condensate system provides water to the 1: emergency feedwater pumps from condensate storage tanks, the primary water supply for these " pumps. The main condenser hotwell can also be aligned to the suction of the emergency

' feedwater pumps as an alternate water supply. The condensate system design flow paths from each of these water sources to the emergency feedwater pumps, satisfying:

1 requirements for plant safe shutdown during a fire. . During a station blackout event, the inventory of the condensate storage tanks is used for heat removal. The condensate system includes the powdex condensate polishers that function to establish and maintain the required quality-of the feedwater delivered to the OTSGs. The water function of the condensate system prevents air from entering the main condenser by:: placing a water seal on valves and pumps subject to condenser vacuum. Due to its interfaces with the main condenser, the condensate system itself functions as part of the pressure boundaw for main condenser vacuum. The condensate system also provides chemical treatment of secondary side water to maintain feedwater pH, feedwater oxygen, and second stage high pressure pH within design limits. Additionally, the condensate system serves as a water supply to !I condenser expansion joints, turbine exhaust hood spray, reactor coolant bleed tanks, and t*e CCCW System.' -. LRA Table 2.3.4-1 identifies the components subject to an AMR for the condensate systemrlby component type and intended function. 2.3.4.1.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concludes there is reasonable assurance that the applicant has Ii' appropriately identified the condensate system components within the scope of license as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system 1: components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21 (a)(1-). . 2.3.4.2 Condensers and Air Removal System 2.3.4.2-,1 Summary of Technical Information in the Application LRA Section 2.3.4.2 describes the condensers & air removal system which is a normally 'i operating system designed primarily to condense and deaerate steam from the main turbine and the main feedwater pump turbines. The condensers & air removal system consists of plant systems including the main condenser, main condenser air removal system, auxiliary .' '_.' condensers, and auxiliary condensers air removal.system. II " The purpose of the main condenser and auxiliary condenser portions of the system is to recover water used in the steam cycle by condensing and deaerating unused steam. The system :: accomplishes this by transferring heat to the circulating water system (which is within the. tube . I 2-74 bundle of the condensers), collecting the condensate, and storing the condensate in the hotwell for reuse in the steam cycle.The purpose of the main condenser and auxiliary condenser air removal portions of the system is to allow the main condenser and auxiliary condensers to operate at vacuum for peak efficiency. It accomplishes this by removing air and non-condensables from the main and auxiliary condensers using vacuum pumps during operation of the main turbine and main feedwater pump turbines.The condensers and air removal system is credited for gas-to-liquid iodine partitioning for thesteam generator tube failure accident and the rod ejection accident. in abnormal operating conditions, the hotwell portion of the condensers and air removal system provides a backup source of water for emergency feedwater system operation. LRA Table 2.3.4-2 identifies the components subject to aging management review for the condensers and air removal system by component type and intended function.2.3.4.2.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concludes there is reasonable assurance that the applicant has appropriately identified the condensers and air removal system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an aging management review in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.4.3 Emergency Feedwater System 2.3.4.3.1 Summary of Technical Information in the Application LRA Section 2.3.4.3 describes the emergency feedwater system which is a standby system designed to remove heat from the primary system when the normal feedwater supply is not available. The emergency feedwater system is capable of holding the plant at hot standby and is also capable of cooling down the plant to the point at which the normal decay heat removal system can operate.The system is not required for plant start-up, normal plant operations or normal shutdown. The system is used only during emergency conditions and periodic testing. The purpose of the emergency feedwater system is to remove heat (including reactor coolant pump energy, decay and sensible heat) from the reactor coolant system to allow safe shutdown of the reactor when the feedwater system is not available. The emergency feedwater system accomplishes this by delivering water to the OTSGs from various water sources.The emergency feedwater system operation is initiated automatically on loss of both main feedwater system pumps, loss of all four reactor coolant pumps, low OTSG water level, high containment pressure, or, it can be initiated manually. The emergency feedwater system will automatically control feedwater flow to maintain water level in the OTSGs. The water level setpoint is based on the status of the reactor coolant pumps. OTSG water levels are maintained higher when all reactor coolant pumps are off to promote natural circulation in the reactor coolant system. Manual control of the emergency feedwater flow to each of the OTSGs is also available to the operator in the main control room.2-75 bundle ofthe condensers), collecting the condensate, and storing the condensate in the hotwell for reuse in the steam cycle. The purpose of the main condenser and auxiliary condenser air removal portions of the system is to allow the main condenser and auxiliary condensers to operate at vacuum for peak efficiency. It accomplishes this by removing air and non-condensables from the main and auxiliary condensers using vacuum pumps during operation of the main turbine and main feedwater pump turbines. The condensers and air removal system is credited for gas-to-liquid iodine partitioning for the steam generator tube failure accident and the rod ejection accident. In abnormal operating conditions, the hotwell portion of the condensers and air removal system provides a backup source of water for emergency feedwater system operation. LRA Table 2.3.4-2 identifies the . components subject to aging management review for*the condensers and air removal system by component type and intended function. 2.3.4.2.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concludes there is reasonable assurance that the applicant has appropriately identified the condensers and air removal system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an aging management review in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.4.3 Emergency Feedwater System 2.3.4.3.1 Summary of Technical Information in the Application LRA Section 2.3.4.3 describes the emergency feedwater system which is a standby system designed to remove heat from the primary system when the normal feedwater supply is not available. The emergency feedwater system is capable of holding the plant at hot standby and is also capable of cooling down the plant to the point at which the normal decay heat removal system can operate. The system is not required for plant start-up, normal plant operations or normal shutdown. The system is used only during emergency conditions and periodic testing. The purpose of the emergency feedwater system is to remove heat (including reactor coolant pump energy, decay and sensible heat) from the reactor coolant system to allow safe shutdown of the reactor when the feedwater system is not available. The emergency feedwater system accomplishes this by delivering water to the OTSGs from various water sources. The emergency feedwater system operation is initiated automatically on loss of both main feedwater system pumps, loss of all tour reactor coolant pumps, low OTSG water level, high containment pressure, or, it can be initiated manually. The emergency feedwater system will automatically control feedwater flow to maintain water level in the OTSGs. The water level setpoint is based on the status of the reactor coolant pumps. OTSG water levels are maintained higher when all reactor coolant pumps are off to promote natural circulation in the reactor coolant system. Manual control of the emergency feedwater flow to each of the OTSGs is also available to the operator in the main control room. 2-75 The emergency feedwater system is designed so that a single failure will not result in the loss of emergency feedwater system function during a LOCA or during a loss of offsite power. The emergency feedwater system is capable of providing emergency feedwater flow to the OTSGs for at least two hours without relying on alternating current (AC) power.LRA Table 2.3.4-3 identifies the components subject to an AMR for the emergency feedwater system by component type and intended function.2.3.4.3.2 Staff Evaluation The staffs review of LRA Section 2.3.4.3 and UFSAR Sections 1.3.2.20, 1.3.2.21, 4.2.5.4, 5.3, 7.1.4, 7.3.2.2.c.16, 9.8.6, 9.10.3, 10.6 and 14.0 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. In RAI 2.3.4.3-1, dated November 24, 2008, the staff noted that on license renewal drawing LR-302-082 the safety-related emergency feedwater control valves to the steam generators are shown within the scope of license renewal. However, the air operators for these valves are nothighlighted, indicating the operators are not within the scope of license renewal. In LRA Section 2.3.4.3 the applicant states that these valves will initially fail closed with loss of air supply to reduce the potential for severe overcooling transients, but that there is adequate time available to the operator to take action to open a flow control valve and restore flow should the flow control valves fail closed. There are multiple sources of air available to ensure their proper positioning during a design basis event in accordance with 10 CFR 54.4(a)(1). License renewal drawing LR-302-273 for the instrument air system shows the instrument air supply up to these emergency feedwater control valves highlighted in green, indicating they are within the scope of license renewal in accordance with 10 CFR 54.4(a)(1) and/or (a)(3).The emergency feedwater control valves' air operators perform a function to change position to regulate flow during a DBE, which would require them to be included within the scope of license renewal under 10 CFR 54.4(a). Even though the operator is an active component, the valve body is passive and requires an AMR in accordance with 10 CFR 54.21. The staff requested that the applicant provide additional information to justify the exclusion of the emergency feedwater control valves' air operators from the scope of license renewal and AMR.In its response to the RAI, dated December 5, 2008, the applicant stated that the air operators for the emergency feedwater system control valves EF-V30A, EF-V30B, EF-V30C, and EF-V30D on license renewal drawing LR-302-082 are not excluded from the scope of license renewal. The applicant stated that on scoping boundary drawings LR-302-032 and LR-302-273 the control valve air operators and their air supplies are properly shown in the scope of license renewal for 10 CFR 54.4(a)(1) criteria and that the four air operator symbols for the four control valves on LR-302-082 should have been colored green as in scope for 10 CFR 54.4(a)(1); however, as active components the control valve air operators are not subject to aging management review.Based on its review, the staff found the applicant's response to RAI 2.3.4.3-1 acceptable because the applicant clarified emergency feedwater system control valves are not excluded from the scope of license renewal, and should have been colored green as in scope for 10 CFR 54.4(a)(1) criteria. The staffs concern described in RAI 2.3.4.3-1 is resolved.2-76 The emergency feedwater system is designed so that a single failure will not result in the loss of emergency feedwater system function during a LOCA or during a loss of offsite power. The, emergency feedwater system is capable of providing emergency feedwater flow to the OTS.Gs for at least two hours without relying on alternating current (AC) power. LRA Table 2.3.4-3 identifies the components subject to an AMR for the emergency feedwater system by component type and intended function. 2.3.4.3.2 Staff Evaluation The staff's review of LRA Section 2.3.4.3 and UFSAR Sections 1.3.2.20, 1.3.2.21, 4.2.5.4, 5.3, 7.1.4, 7.3.2.2.c.16, 9.B.6, 9.10.3,10.6 and 14.0 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. :; In RAI 2.3.4.3-1, dated November 24, 200B, the staff noted that on license renewal drawing LR-302-0B2 the safety-related emergency feedwater control valves to the steam generators are shown within the scope of license renewal. However, the air operators for these valves are not highlighted, indicating the operators are not within the scope of license renewal. In LRA Section 2.3.4.3 the applicant states that these valves will initially fail closed with loss of air supply to reduce the potential for severe overcooling transients, but that there is adequate time available to the operator to take action to open a flow control valve and restore flow should the flow cbntrol valves fail closed. There are multiple sources of air available to ensure their proper pOSitioning during a design basis event in accordance with 10 CFR 54.4(a)(1). License renewal drawing LR-302-273 for the instrument air system shows the instrument air supply up to these emergency feedwater control valves highlighted in green, indicating they are within the scope of license renewal in accordance with 10 CFR 54.4(a)(1) and/or (a)(3). The emergency feedwater control valves' air operators perform a function to change position to regulate flow during a DBE, which would require them to be included within the scope of renewal under 10 CFR 54.4(a). Even though the operator is an active component, the valve body is passive and requires an AMR in accordance with 10 CFR 54.21. The staff requested that the applicant provide additional information to justify the exclusion of the emergency feedwater control valves' air operators from the scope of license renewal and AMR. In its response to the RAI, dated December 5, 200B, the applicant stated that the air for the emergency feedwater system control valves EF-V30A, EF-V30B, EF-V30C, and EF-V30D on license renewal drawing LR-302-0B2 are not excluded from the scope of license renewal. The applicant stated that on scoping boundary drawings LR-302-032 and LR-302-273 the contr91 valve air operators and their air supplies are properly shown in the scope of license renewal for 10 CFR 54.4(a)(1) criteria and that the four air operator symbols for the four control valves on LR-302-0B2 should have been colored green as in scope for 10 CFR 54.4(a)(1); however, as aCtive components the control valve air operators are not subject to aging management review. Based on its review, the staff found the applicant's response to RAI 2.3.4.3-1 acceptable because the applicant clarified emergency feedwater system control valves are not excluded from the scope of license renewal, and should have been colored green as in scope for 10 CFR 54.4(a)(1) criteria. The staff's concern described in RAI 2.3.4.3-1 is resolved. 2-76 2.3.4.3.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the emergency feedwater system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an aging management review in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.4.4 Extraction Steam System 2.3.4.4.1 Summary of Technical Information in the Application LRA Section 2.3.4.4 describes the extraction steam system which consists of the following plant systems: extraction steam (high pressure & low pressure) system, feedwater heater drains system, and the feedwater heater vents, reliefs, and miscellaneous drains system.The extraction steam system is a normally operating system designed to deliver steam from the high and low pressure sections of the main turbine to secondary side plant components. Steam is delivered to the feedwater heaters for feedwater preheating, which improves overall plant efficiency. Steam is also delivered to the following components to support their process functions: main feedwater pump turbines, radioactive waste evaporators, auxiliary boilers, and the caustic solution heater used for mixed bed regeneration. The extraction steam system includes the heater drain pumps, which return condensed steam from the sixth stage collection drain tank to the feedwater system, heater vents that discharge non-condensable gases to the moisture separators and the main condenser, and relief valves that discharge through a common header to atmosphere. During normal and abnormal operating conditions, due to its interfaces with the main condenser, the extraction steam system functions as part of the pressure boundary for main condenser vacuum. Main condenser vacuum boundary is required to mitigate the steam generator tube failure accident and the rod ejection accident.LRA Table 2.3.4-4 identifies the components subject to an AMR for the Extraction Steam System by component type and intended function.2.3.4.4.2 Staff Evaluation The staffs review of LRA Section 2.3.4.4 and UFSAR Sections 10.3.3, 14.1.2.10, 14.2.2.2, and Table 10.4-1 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.In RAI 2.3.4.4-1, dated August 20, 2008, the staff noted that LRA Section 2.3.4.4 states that the extraction steam system meets the requirements of 10 CFR 54.4(a)(1), because it is a system that is relied upon to remain functional during and following DBEs. The staff could not identify the functions that support the 10 CFR 54.4(a)(1) designation provided by the extraction steam to verify the applicant did not omit any components from the scope of license renewal. The staff requested that the applicant provide additional information concerning the functions that support the 10 CFR 54.4(a)(1) designation provided by the extraction steam system and identify the components that perform these functions. 2-77 2.3.4.3.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the emergency feedwater system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an aging management review in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.4.4 Extraction Steam System 2.3.4.4.1 Summary of Technical Informaition in the Application LRA Section 2.3.4.4 describes the extraction steam system which consists of the following plant systems: extraction steam (high pressure & low pressure) system, feedwater heater drains system, and the feedwater heater vents, reliefs, and miscellaneous drains system. The extraction steam system is a normally operating system designed to deliver steam from the high and low pressure sections of the main turbine to secondary side plant components. Steam is delivered to the feedwater heaters for feedwater preheating, which improves overall plant efficiency. Steam is also delivered to the following components to support their process functions: main feedwater pump turbines, radioactive waste evaporators, auxiliary boilers, and the caustic solution heater used for mixed bed regeneration. The extraction steam system includes the heater drain pumps, which return condensed steam from the sixth stage collection drain tank to the feedwater system, heater vents that discharge non-condensable gases to the moisture separators and the main condenser, and relief valves that discharge through a common header to Citmosphere. During normal and abnormal operating conditions, due to its interfaces with the main condenser, the extraction steam system functions as part of the pressure boundary for main condenser vacuum. Main condenser vacuum boundary is required to mitigate the steam generator tube failure accident and the rod ejection accident. LRA Table 2.3.4-4 identifies the components subject to an AMR for the Extraction Steam System . by component type and intended function. 2.3.4.4.2 Staff Evaluation The staff's review of LRA Section 2.3.4.4, and UFSAR Sections 10.3.3, 14.1.2.10, 14.2.2.2, and Table 10.4-1 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below. In RAI 2.3.4.4-1, dated August 20, 2008, the staff noted that LRA Section 2.3.4.4 states that the extraction steam system meets the req uirements of 10 CFR 54.4( a)( 1), because it is a system that is relied upon to remain functional during and following DBEs. The staff could not identify the functions that support the 10 CFR 54.4(a)(1) designation provided by the extraction steam to verify the applicant did not omit any components from the scope of license renewal. The staff requested that the applicant provide additional information concerning the functions that support the 10 CFR 54.4( a)( 1) designation provided by the extraction steam system and identify the components that perform these functions. 2-77 In its response to the RAI, dated September 16, 2008, the applicant stated that the extraction steam system performs no 10 CFR 54.4(a)(1) intended functions. The applicant stated that LRA Section 2.3.4.4, incorrectly states that the extraction steam system meets 10 CFR 54.4(a)(1) scoping criteria. The applicant stated that the extraction steam system is in scope for license renewal because it only meets 10 CFR 54.4(a)(2) criteria. In its response, the applicant amended the LRA by revising the first sentence in LRA Section 2.3.4.4 to explain why the system was not in scope under 10 CFR 54.4(a)(1) criteria.Based on its review, the staff finds the applicant's response to RAI 2.3.4.4-1 acceptable because the applicant clarified that the extraction steam system performs no 10 CFR 54.4(a)(1) intended function. The staffs concern described in RAI 2.3.4.4-1 is resolved.2.3.4.4.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the extraction steam system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.4.5 Feedwater System 2.3.4.5.1 Summary of Technical Information in the Application LRA Section 2.3.4.5 describes the feedwater system which is a normally operating system designed to maintain level in the OTSGs. The feedwater system is not required for safe plantshutdown or for maintaining the plant in the shutdown condition. The feedwater system consists of several plant systems including the main feedwater system, main feed pump turbines and auxiliaries system, and feedwater pump shaft seals & leakoff system.The purpose of the feedwater system is to maintain level in the OTSGs throughout all modes of normal plant operation. The feedwater system accomplishes this by further heating deaerated, treated, and preheated condensate from the condensate system and delivering it to the OTSGs. The feedwater system delivers the water to the OTSGs to match the steam demand for the turbine load.The feedwater system isolation and regulating valves automatically close to stop flow to the OTSGs on Hi-Hi OTSG level or indication of a feedwater or main steam system line break.Feedwater system isolation must be provided during an appendix R shutdown and is accomplished through the manual closure of the feedwater system isolation or regulating valves.The feedwater line to each OTSG is also provided with a check valve which serves as the reactor building isolation valve. The feedwater system pump turbine casing, pump recirculation linell and secondary side drains are necessary to establish the main condenser vacuum boundary, which is required to mitigate the steam generator tube failure accident and the rod ejection accident.,, LRA Table 2.3.4-5 identifies the components subject to an AMR for the Feedwater System by component type and intended function.2.3.4.5.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has 2-78 In its response to the RAI, dated September 16, 2008, the applicant stated that the extraction steam system performs no 10 CFR 54.4(a)(1) intended functions. The applicant stated that LRA Section 2.3.4.4, incorrectly states that the extraction steam system meets 10 CFR 54.4(a)(1) scoping criteria. The applicant stated that the extraction steam system is in scope for license renewal because it only meets 10 CFR 54.4(a)(2) criteria. In its response, the applicant amended the LRA by revising the first sentence in LRA Section 2.3.4.4 to explain why the system was not in scope under 10 CFR 54.4(a)(1) criteria. Based on its review, the staff finds the applicant's response to RAI 2.3.4.4-1 acceptable because the applicant clarified that the extraction steam system performs no 10 CFR 54.4(a)(1) intended function. The staffs concern described in RAI2.3.4.4-1 is resolved. . 2.3.4.4.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the extraction steam system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.4.5 Feedwater System 2.3.4.5.1 Summary of Technical Information in the Application LRA Section 2.3.4.5 describes the feedwater system which is a normally operating system :; designed to maintain level in the OTSGs. The feedwater system is not required for safe plart shutdown or for maintaining the plant in the shutdown condition. The feedwater system of several plant systems including the main feedwater system, main feed pump turbines and auxiliaries system, and feedwater pump shaft seals &: leakoff system. The purpose of the feedwater system is to maintain level in the OTSGs throughout all modes of normal plant operation. The feedwater system accomplishes this by further heating deaerated, treated, and preheated condensate from the condensate system and delivering it to the OTSGs. The feedwater system delivers the water to the OTSGs to match the steam demand for the turbine load. The feedwater system isolation and regulating valves automatically close to stop flow to the OTSGs on Hi-Hi OTSG level or indication of a feedwater or main steam system line break. Feedwater system isolation must be provided during an appendix R shutdown and is accomplished through the manual closure of the feedwater system isolation or regulating valves. The feedwater line to each OTSG is also provided with a check valve which serves as the rbactor building isolation valve. The feedwater system pump turbine casing, pump recirculation line l; and secondary side drains are necessary to establish the main condenser vacuum boundary, wrich is required to mitigate the steam generator tube failure accident and the rod ejection accident.,' LRA Table 2.3.4-5 identifies the components subject to an AMR for the Feedwater System by component type and intended function. 2.3.4.5.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has 2-78 appropriately identified the feedwater system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified thesystem components subject to an aging management review in accordance with the requirements stated in 10 CFR 54.21 (a)(1).2.3.4.6 Main Generator and Auxiliary Systems 2.3.4.6.1 Summary of Technical Information in the Application LRA Section 2.3.4.6 describes the main generator and auxiliary systems whose intended function for license renewal is to maintain leakage boundary integrity to preclude system interactions. For this reason, the system's pressure retaining components located in proximity to other components performing'safety-related functions have been included in the scope of license renewal.The main generator and auxiliary systems is a normally operating system designed to convert the mechanical energy of the main turbine into electrical energy for distribution to the grid. The main generator and auxiliary system consists of several plant systems including the main generator, main generator excitation system, isolated phase bus duct cooling system, generator seal oil system, generator hydrogen cooling system, generator gas & vents system, and stator cooling system.The purpose of the main generator and auxiliary system is to produce electricity. The system accomplishes this by converting mechanical energy provided by the main turbine into electrical energy. The electrical energy produced by the main generator is fed through an isolated phase bus to the main transformers for distribution to the grid. LRA Table 2.3.4-6 identifies the components subject to aging management review for the main generator and auxiliary systems by component type and intended function.2.3.4.6.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concludes there is reasonable assurance that the applicant has appropriately identified the main generator and auxiliary system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.4.7 Main Steam System 2.3.4.7.1 Summary of Technical Information in the Application LRA Section 2.3.4.7 describes the main steam system which is a safety-related, normally operating system, designed to deliver energy in the form of steam, from the primary side of the plant to secondary side systems. The main steam system is capable of delivering steam to support normal plant operation up to 100% of design capacity and to support the plant cool-downduring both normal operating conditions and design basis events.The purpose of the main steam system is to provide steam to the appropriate secondary system components based on the plant conditions. It accomplishes this by directing steam to the turbine generator and main feedwater pump turbines during normal plant operation. Additionally, itprovides gland seal steam and steam for relief valve support post heating. The main steam 2-79 appropriately identified the feedwater system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an aging management review in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.4.6 Main Generator and Auxiliary Systems 2.3.4.6.1 Summary of Technical Information in the Application LRA Section 2.3.4.6 describes the main generator and auxiliary systems whose intended function for license renewal is to maintain leakage boundary integrity to preclude system interactions. For this reason, the system's pressure retaining components located in proximity to other components performing* safety-related functions have been included in the scope of license renewal. The main generator and auxiliary systems is a normally operating system designed to convert the mechanical energy of the main turbine into electrical energy for distribution to the grid. The main generator and auxiliary system consists of several plant systems including the main generator, main generator excitation system, isolated phase bus duct cooling system, generator seal oil system, generator hydrogen cooling system, generator gas & vents system, and stator cooling system. .... :-The purpose of the main generator and auxiliary system is to produce electricity. The system accomplishes this by converting mechanical energy provided by the main turbine into electrical energy. The electrical energy produced by the main generator is fed through an isolated phase bus to the main transformers for distribution to the grid. LRA Table 2.3.4-6 identifies the components subject to aging management review for the main generator and auxiliary systems by component type and intended function. 2.3.4.6.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concludes there is reasonable assurance that the applicant has appropriately identified the main generator and auxiliary system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). .. 2.3.4.7 Main Steam System 2.3.4.7.1 Summary of Technical Information in the Application LRA Section 2.3.4.7 describes the main steam system which is a safety-related, normally operating system, designed to deliver energy in the form of steam, from the primary side of the plant to secondary side systems. The main steam system is capable of delivering steam to support normal plant operation up to 100% of design capacity and to support the plant cool-down during both normal operating conditions and design basis events. The purpose of the main steam system is to provide steam to the appropriate secondary system components based on the plant conditions. It accomplishes this by directing steam to the turbine generator and main feedwater pump turbines during normal plant operation. Additionally, it provides gland seal steam and steam for relief valve support post heating. The main steam 2-79 system includes moisture separators that remove moisture from steam exiting the high-pressure portion of the main turbine generator. In abnormal conditions, steam can be directed to theemergency feedwater pump turbine, the main condenser via the turbine bypass valves, or to the atmospheric dump valves as required to support safe shutdown of the plant.During normal and abnormal operating conditions, due to its interfaces with the main condenser, the main steam system functions as part of the pressure boundary for main condenser vacuum.Main condenser vacuum boundary is required to mitigate the steam generator tube failure accident and the rod ejection accident. The functions of the main steam system are (1) main steam delivery, (2) relief valve support heating, (3) steam dump and turbine bypass, and (4)moisture separation. LRA Table 2.3.4-7 identifies the components subject to an AMR for the Main Steam System by component type and intended function.2.3.4.7.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the main steam system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identifiedthe system components subject to an aging management review in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.4.8 Steam Turbine and Auxiliary Systems 2.3.4.8.1 Summary of Technical Information in the Application LRA Section 2.3.4.8 describes the steam turbine and auxiliary system which is a normally operating system designed to convert the thermodynamic energy generated in the primary side of the plant into rotational mechanical energy to drive the main generator at the output of the plant.The steam turbine and auxiliary system consists of the following plant systems: main turbine, electro-hydraulic control (EHC) system, turbine lift oil and lube oil system, turbine oil purific1ationand transfer system, gland seal system, turbine drains, and main turbine exhaust hood spray.The purpose of the steam turbine and auxiliary system is to convert thermal energy into mechanical energy. The system accomplishes this by receiving thermal energy in the form of pressurized steam from the OTSGs, converting this thermal energy to mechanical energy through rotation of the turbine shaft. Exhaust steam is discharged into the main condenser, part of the condenser and air removal system. The main turbine system is directly connected to the main electric generator, part of the main generator and auxiliary system, which produces electrical energy for plant output. Turbine control is effected through the operation of the EHC system.The turbine lift oil and lube oil system supplies oil to the main turbine thrust and journal bearings for heat removal and lubrication and maintains the quality of the oil.The gland steam system provides low pressure steam for sealing main and feedwater pumpturbine rotors and valve stems of the main turbine stop and control valves.The turbine drain system provides moisture and water removal from steam lines to prevent water induction into the turbine.2-80 system includes moisture separators that remove moisture from steam exiting the high-pressure portion of the main turbine generator. In abnormal conditions, steam can be directed to the emergency feedwater pump turbine, the main condenser via the turbine bypass valves, or to the atmospheric dump valves as required to support safe shutdown of the plant. During normal and abnormal operating conditions, due to its interfaces with the main condenser, the main steam system functions as part of the pressure boundary for main condenser vacdum. Main condenser vacuum boundary is required to mitigate the steam generator tube failure accident and the rod ejection accident. The functions of the main steam system are (1) mair:1 steam delivery, (2) relief valve support heating, (3) steam dump and turbine bypass, and (4) moisture separation. LRA Table 2.3.4-7 identifies the components subject to an AMR for the Main Steam System by component type and intended function. 2.3.4.7.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the main steam system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately iden1tified the system components subject to an aging management review in accordance with the requirements stated in 10 CFR 54.21(a)(1). 2.3.4.8 Steam Turbine and Auxiliary Systems 2.3.4.8.1 Summary of Technical Information in the Application LRA Section 2.3.4.8 describes the steam turbine and auxiliary system which is a normally operating system designed to convert the thermodynamic energy generated in the primary side of the plant into rotational mechanical energy to drive the main generator at the output of the plant. The steam turbine and auxiliary system consists of the following plant systems: main turbine, electro-hydraulic control (EHC) system, turbine lift oil and lube oil system, turbine oil and transfer system, gland seal system, turbine drains, and main turbine exhaust hood spray. The purpose of the steam turbine and auxiliary system is to convert thermal energy into mechanical energy. The system accomplishes this by receiving thermal energy in the form of pressurized steam from the OTSGs, converting this thermal energy to mechanical energy through rotation of the turbine shaft. Exhaust steam is discharged into the main condenser, part of the condenser and air removal system. The main turbine system is directly connected to the main electric generator, part of the main generator and auxiliary system, which produces electric,al energy for plant output. Turbine control is effected through the operation of the EHC system. I, The turbine lift oil and lube oil system supplies oil to the main turbine thrust and journal bearings for heat removal and lubrication and maintains the quality of the oil. The gland steam system provides low pressure steam for sealing main and feedwater pump turbine rotors and valve stems of the main turbine stop and control valves. The turbine drain system provides moisture and water removal from steam lines to water induction into the turbine. 2-80 The main turbine exhaust hood spray system provides cooling water to exhaust hood areas to prevent distortion of the turbine casings and support structures. During normal and abnormal operating conditions, the steam turbine and auxiliary system functions as part of the pressure boundary for main condenser vacuum.LRA Table 2.3.4-8 identifies the components subject to aging management review for the Steam Turbine and Auxiliary Systems by component type and intended function.2.3.4.8.2 Staff Evaluation The staffs review of LRA Section 2.3.4.8 and UFSAR Sections 7.1.2, 10.2.1, 10.2.2, 10.2.3,14.1.2.9, 14.1.2.10, 14.2.2.2, and LRA Tables 10.2-1 and 10.2-2 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results.In RAI 2.3.4.8-1, dated August 20, 2008, the staff noted that on license renewal drawing LR-302-141, a turbine gland seal atmospheric drain tank is highlighted in red, indicating that it is within the scope of license renewal for 10 CFR 54.4(a)(2) criteria. Typically, this component type has a leakage boundary function. LRA Table 2.3.4-8 includes tanks as a component type and itemizes which tanks are included. However, the table does not include the turbine gland seal atmospheric drain tank as a component subject to an AMR. The staff requested that the applicant provide additional information to justify the exclusion of the turbine gland seal atmospheric drain tank from LRA Table 2.3.4-8. In its response to the RAI, dated September 16, 2008, the applicant stated that the turbine gland seal atmospheric drain tank is a nonsafety-related tank within the scope of license renewal with a leakage boundary function and subject to aging management review; however, the tank is part of the condensate system and should have been included in LRA Tables 2.3.4-1 and 3.4.2-1. The applicant stated that boundary flags on license renewal drawings LR-302-141 and LR-302-172 incorrectly indicate the turbine gland seal atmospheric drain tank and associated piping as being part of the steam turbine and auxiliaries system. The applicant also stated that on license renewal drawing LR-302-141, one steam turbine and auxiliary's system flag should have been shown as a condensate system flag. The applicant amended the LRA by listing the turbine gland seal atmospheric drain tank with tanks of the same material, environment and aging effects under the component tanks with an intended function of leakage boundary in LRA Table 2.3.4-1. The applicant also amended the LRA by listing the turbine gland seal atmospheric drain tank under tanks with identical material, environment, and aging effects in LRA Table 3.4.2-1 with complete AMR results.Based on its review, the staff finds the applicant's response to RAI 2.3.4.8-1 acceptable because the applicant added the component "tanks" with an intended function of leakage boundary to the LRA Tables 2.3.4-1 and 3.4.2-1. The staff's concern described in RAI 2.3.4.8-1 is resolved.In RAI 2.3.4.8-2, dated November 24, 2008, the staff noted that in LRA Section 2.3.4.2 the applicant stated that the condenser shell has the intended function of pressure boundary in accordance with 10 CFR 54.4(a)(2) for iodine partitioning. Typically on the turbine pedestal, there are drain lines originating in each of the wells where the turbine shaft penetrates the low pressure turbine housings for the purpose of draining condensate from excessive gland sealing steam.These drain lines penetrate the condenser housing where they originate and where they exit.2-81 The main turbine exhaust hood spray system provides cooling water to exhaust hood areas to prevent distortion of the turbine casings and support structures. During normal and abnormal operating conditions, the steam turbine and auxiliary system functions as part of the pressure boundary for main condenser vacuum. LRA Table 2.3.4-8 identifies the components subject to aging management review for the Steam Turbine and Auxiliary Systems by component type and intended function. 2.3.4.8.2 Staff Evaluation The staffs review of LRA Section 2.3.4.8 and UFSAR Sections 7.1.2, 10.2.1, 10.2.2, 10.2.3, 14.1.2.9, 14.1.2.10, 14.2.2.2, and LRA Tables 10.2-1 and 10.2-2 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results." In RAI 2.3.4.8-1, dated August 20,2008, the staff noted that on license renewal drawing LR-302-141, a turbine gland seal atmospheric drain tank is highlighted in red, indicating that it is within the scope of license renewal for 10 CFR 54.4(a)(2) criteria. Typically, this component type has a leakage boundary function. LRA Table 2.3.4-8 includes tanks as a component type and itemizes which tanks are included. However, the table does not include the turbine gland seal atmospheric drain tank as a component subject to an AMR. The staff requested that the applicant provide additional information to justify the exclusion of the turbine gland seal atmospheric drain tank from LRA Table 2.3.4-8. In its response to the RAI, dated September 16, 2008, the applicant stated that the turbine gland seal atmospheric drain tank is a nonsafety-related tank within the scope of license renewal with a leakage boundary function and subject to aging management review; however, the tank is part of the condensate system and should have been included in LRA Tables 2.3.4-1 and 3.4.2-1. The applicant stated that boundary flags on license renewal drawings LR-302-141 and LR-302-172 incorrectly indicate the turbine gland seal atmospheric drain tank and associated piping as being part of the steam turbine and auxiliaries system. The applicant also stated that on license renewal drawing LR-302-141, one steam turbine and auxiliary's system flag should have been shown as a condensate system flag. The applicant amended the LRA by listing the turbine gland seal atmospheric drain tank with tanks of the same material, environment and aging effects under the component tanks with an intended function of leakage boundary in LRA Table 2.3.4-1. The applicant also amended the LRA by listing the turbine gland seal atmospheric drain tank under tanks with identical material, environment, and aging effects in LRA Table 3.4.2-1 with complete AMR results. Based on its review, the staff finds the applicant's response to RAJ 2.3.4.8-1 acceptable because the applicant added the component "tanks" with an intended function of leakage boundary to the LRA Tables 2.3.4-1 and 3.4.2-1. The staff's concern described in RAI 2.3.4.8-1 is resolved. In RAI 2.3.4.8-2, dated November 24, 2008, the staff noted that in LRA Section 2.3.4.2 the applicant stated that the condenser shell has the intended function of pressure boundary in accordance with 10 CFR 54.4(a)(2) for iodine partitioning. Typically on the turbine pedestal, there are drain lines originating in each of the wells where the turbine shaft penetrates the low pressure turbine housings for the purpose of draining condensate from excessive gland sealing steam. These drain lines penetrate the condenser housing where they originate and where they exit. 2-81 Neither LRA Section 2.3.4.2 nor Section 2.3.4.8 discuss this drain piping usually referred to as"slop drains." The failure of this piping is routinely reported in the industry and noted as a source of air inleakage to the condenser affecting vacuum. This drain piping would be a part of the pressure boundary for the condenser and included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2) as a functional (a)(2) because its failure would affect the condenser shell's pressure boundary intended function. The staff requested that the applicant provide additional information to clarify whether the turbine pedestal "slop drains" lines are present and also justify their exclusion from the scope of license renewal under 10 CFR 54.4(a)(2). In its response to the RAI, dated December 5, 2008, the applicant stated that the turbine pedestal"slop drains" are present and included in the scope of license renewal. The applicant stated that the drains perform a 10 CFR 54.4(a)(2) criteria intended function of functional support, because they form a portion of the pressure boundary for condenser shell vacuum, which is required for iodine partitioning and that the drains are shown on license renewal drawings LR-302-306 and LR-302-307 as 2-inch drain lines from the low-pressure turbine bearing drip pans to collection tanks LO-T-7A, LO-T-7B, and LO-T-7C. The applicant stated that this drain piping was incorrectly colored as red on the license renewal drawings and should have been colored green, representing a pressure boundary intended function.Based on its review, the staff found the applicant's response to RAI 2.3.4.8-2 acceptable, because the applicant clarified the turbine pedestal "slop drains" are present, are in the scope of license renewal with a pressure boundary intended function, and should have been colored green. The staffs concern described in RAI 2.3.4.8-2 is resolved.2.3.4.8.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the steam turbine and auxiliary system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21 (a)(1).2.4 Scoping and Screening Results: Structures This section documents the staffs review of the applicant's scoping and screening results for structures. Specifically, this section describes the following structures:

  • Air intake structure* Auxiliary building* Circulating water pump house* Control building* Diesel generator building* Dike/Flood control system* Fuel handling building* Intake screen and pump house* Intermediate building* Mechanical draft cooling tower structures
  • Miscellaneous yard structures
  • Natural draft cooling tower 2-82 Neither LRA Section 2.3.4.2 nor Section 2.3.4.8 discuss this drain piping usually referred to as "slop drains." The failure of this piping is routinely reported in the industry and noted as a source of air inleakage to the condenser affecting vacuum. This drain piping would be a part of the pressure boundary for the condenser and included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2) as a functional (a)(2) because its failure would affect the condenser shell's pressure boundary intended function.

The staff requested that the provide additional information to clarify whether the turbine pedestal "slop drains" lines are

  • present and also justify their exclusion from the scope of license renewal under 10 CFR 54.4(a)(2).

In its response to the RAI, dated December 5,2008, the applicant stated that the turbine pedestal "slop drains" are present and included in the scope of license renewal. The applicant stated that the drains perform a 10 CFR 54.4(a)(2) criteria intended function of functional support, because they form a portion of the pressure boundary for condenser shell vacuum, which is required for iodine partitioning and that the drains are shown on license renewal drawings LR-302-306 LR-302-307 as 2-inch drain lines from the low-pressure turbine bearing drip pans to collection tanks LO-T-7A, LO-T-7B, and LO-T-7C. The applicant stated that this drain piping was inco'rrectly colored as red on the license renewal drawings and should have been colored green, representing a pressure boundary intended function. Based on its review, the staff found the applicant's response to RAI 2.3.4.8-2 acceptable, because the applicant clarified the turbine pedestal "slop drains" are present, are in the scope' of license renewal with a pressure boundary intended function, and should have been colored green. The staff's concern described in RAI 2.3.4.8-2 is resolved. 2.3.4.8.3 Conclusion On the basis of its review, the staff concludes that the applicant has adequately identified the stearn turbine and auxiliary system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21 (a)(1). 2.4 Scoping and Screening Results: Structures This section documents the staff's review of the applicant's scoping and screening results for structures. Specifically, this section describes the following structures: .

  • Air intake structure
  • Auxiliary building
  • Circulating water pump house
  • Control building
  • Diesel generator building
  • Dike/Flood control system
  • Fuel handling building
  • Intake screen and pump house
  • Intermediate building
  • Mechanical draft cooling tower structures
  • Miscellaneous yard structures
  • Natural draft cooling tower 2-82
  • Structural commodities
  • Reactor building 0 SBO diesel generator building* Service building* Component supports commodity group* Substation structures
  • Turbine building" UPS diesel building In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant identified and listed passive, long-lived SCs that are within the scope of license renewal and subject to an AMR. To verify that the applicant properly implemented its methodology, the staff focused its review on the implementation results. This approach allowed the staff to confirm that there were no omissions of structural components that meet the scoping criteria and are subject to an AMR.The staffs evaluation of the information provided in the LRA was performed in the same manner for all structures.

The objective of the review was to determine if the structural components that appeared to meet the scoping criteria specified in the Rule, were identified by the applicant as within the scope of license renewal, in accordance with 10 CFR 54.4. Similarly, the staff evaluated the applicant's screening results to verify that all long-lived, passive SCs were subject to an AMR in accordance with 10 CFR 54.21(a)(1). To perform its evaluation, the staff reviewed the applicable LRA sections, focusing its review on components that had not been identified as within the scope of license renewal. The staff reviewed the UFSAR for each structure to determine if the applicant had omitted components with intended functions delineated under 10 CFR 54.4(a) from the scope of license renewal. The staff also reviewed the UFSAR to determine if all intended functions delineated under 10 CFR 54.4(a)were specified in the LRA. If omissions were identified, the staff requested additional information to resolve the discrepancies. Once the staff completed its review of the scoping results, the staff evaluated the applicant's screening results. For those components with intended functions, the staff sought to determine:(1) if the functions are performed with moving parts or a change in configuration or properties, or (2) if they are subject to replacement based on a qualified life or specified time period, as described in 10 CFR 54.21(a)(1). For those that did not meet either of these criteria, the staff sought to confirm that these structural components were subject to an AMR as required by 10 CFR 54.21(a)(1). If discrepancies were identified, the staff requested additional information to resolve them.2.4.1 Air Intake Structure 2.4.1.1 Summary of Technical Information in the Application LRA Section 2.4.1 describes the air intake structure which is a seismic class I reinforced concrete structure located approximately 300 feet southwest of the reactor building. The air intake structure includes an above grade reinforced concrete box like structure and a below grade tunnel that provides a pathway for outside air from the air intake to the auxiliary building, control building and fuel handling building.2-83* Structural commodities

  • Reactor building
  • SSO diesel generator building
  • Service building
  • Component supports commodity group
  • SUbstation structures
  • Turbine building
  • UPS diesel building In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant identified and listed passive, long-lived SCs that are within the scope of license renewal and subject to an AMR. To verify that the applicant properly implemented its methodology, the staff focused its review on the implementation results. This approach allowed the staff to confirm that there were no omissions of structural components that meet the scoping criteria and are subject to an AMR. The staffs evaluation of the information provided in the LRA was performed in the same manner for all structures.

The objective of the review was to determine if the structural components that appeared to meet the scoping criteria specified in the Rule, were identified by the applicant as within the scope of license renewal, in accordance with 10 CFR 54.4. Similarly, the staff evaluated the applicant's screening results to verify that all long-lived, passive SCs were subject to an AMR in accordance with 10 CFR 54.21 (a)(1). To perform its evaluation, the staff reviewed the applicable LRA sections, focusing its review on components that had not been identified as within the scope of license renewal. The staff reviewed the UFSAR for each structure to determine if the applicant had omitted components with intended functions delineated under 10 CFR 54.4(a) from the scope of license renewal. The staff also reviewed the UFSAR to determine if all intended functions delineated under 10 CFR 54.4(a) were specified in the LRA. If omissions were identified, the staff requested additional information to resolve the discrepancies. Once the staff completed its review of the scoping results, the staff the applicant's screening results. For those components with intended functions, the staff sought to determine: (1) if the functions are performed with moving parts or a change in configuration or properties, or (2) if they are subject'to replacement based on a qualified life or specified time period, as described in 10 CFR 54.21 (a)( 1). For those that did not meet either of these criteria, the staff sought to confirm that these structural components were subject to an AMR as required by 10 CFR 54.21 (a)(1). If discrepancies were identified, the staff requested additional information to resolve them. 2.4.1 Air Intake Structure 2.4.1.1 Summary of Technical Information in the Application LRA Section 2.4.1 describes the air intake structure which is a seismic class I reinforced concrete structure located approximately 300 feet southwest of the reactor building. The air intake structure includes an above grade reinforced concrete box like structure and a below grade tunnel that provides a pathway for outside air from the air intake to the auxiliary building, control building and fuel handling building. 2-83 The purpose of the air intake structure is to provide a source of makeup air or outside air to the ventilation systems of the auxiliary, control, and fuel handling buildings and to provide structural support, shelter and protection for the components housed within.LRA Table 2.4-1 identifies the components subject to an AMR for the air intake structure by component type and intended function.2.4.1.2 Conclusion The staff followed the evaluation methodology discussed in Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the Air Intake Structure SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21 (a)(1).2.4.2 Auxiliary Building 2.4.2.1 Summary of Technical Information in the Application LRA Section 2.4.2 describes the auxiliary building, which includes the auxiliary building, heat exchanger vault, access tunnel vault, exhaust air tunnel, chem storage room, and ESF ventilation room. The auxiliary building is a seismic class I structure located south west of the reactor building and west of the fuel handling building, and is a reinforced concrete structure with one story above grade.The heat exchanger vault is a seismic class I reinforced concrete structure attached to the west wall of the auxiliary building. The access tunnel vault is a seismic class I reinforced concrete structure attached to the north wall of the auxiliary building. The exhaust air tunnel is a seismic class I reinforced concrete structure attached to the north wall of the auxiliary building. The chem storage and ESF ventilation rooms are separate, nonsafety-related, steel-framed structures, with metal siding and metal roofing protected with roofing materials, located on the auxiliary building reinforced concrete roof slab.The auxiliary building, heat exchanger vault, access tunnel vault, and exhaust air tunnel are designed for normal operating loads and to withstand the effects of design basis accident loads as applicable. The chem storage room and ESF ventilation room are designed for normal operating loads only.The purpose of the auxiliary building, access tunnel vault, and heat exchanger vault is to provide structural support, shelter, and protection for vital mechanical and electrical equipment required for safe operation of the plant, including safe shutdown of the reactor. The purpose of the exhaust air tunnel portion of the auxiliary building is to allow exhaust air from the auxiliary building, reactor building, fuel handling building, and control building ventilation systems to be directed to the exhaust vent stack located on the west side of the reactor building. The purpose of the chem storage and ESF ventilation rooms is to provide structural support, shelter, and protection fornonsafety-related equipment housed within, and to maintain their structural integrity to ensure that they will not adversely affect the components housed within, or the auxiliary building, from performing their intended functions. 2-84 The purpose of the air intake structure is to provide a source of makeup air or outside air to the ventilation systems of the auxiliary, control, and fuel handling buildings and to provide structural support, shelter and protection for the components housed within. LRA Table 2.4-1 identifies the components subject to an AMR for the air intake structure by component type and intended function. 2.4.1.2 Conclusion The staff followed the evaluation methodology discussed in Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to 'identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the Air Intake Structure SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and thpse subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.4.2 Auxiliary

Building 2.4.2.1 Summary of Technical Information in the Application LRA Section 2.4.2 describes the auxiliary building, which includes the auxiliary building, heat exchanger vault, access tunnel vault, exhaust air tunnel, chern storage room, and ESF ventilation room. The auxiliary building is a seismic class I structure located south west of the reactor building and west of the fuel handling building, and is a reinforced concrete structure with one story above grade. The heat exchanger vault is a seismic class I reinforced concrete structure attached to the west wall of the auxiliary The access tunnel vault is a seismic class I reinforced concrete structure attached to the north wall of the auxiliary building. The exhaust air tunnel is a seismic class I reinforced concrete structure attached to the north wall of the auxiliary building. The chern storage and ESF ventilation rooms are separate, nonsafety-related, steel-framed structures, with, metal siding and metal roofing protected with roofing materials, located on the auxiliary building reinforced concrete roof slab. ' The auxiliary building, heat exchanger vault, access tunnel vault, and exhaust air tunnel are designed for normal operating loads and to withstand the effects of design basis accident loads as applicable. The chern storage room and ESF ventilation room are designed for normal operating loads only. The purpose of the auxiliary building, access tunnel vault, and heat exchanger vault is to structural support, shelter, and protection for vital mechanical and electrical equipment required for safe operation of the plant, including safe shutdown of the reactor. The purpose of the exhaust air tunnel portion of the auxiliary building is to allow exhaust air from the auxiliary building, reactor building, fuel handling building, and control building ventilation systems to be directed to the exhaust vent stack located on the west side of the reactor building. The purpose of the chern storage and ESF ventilation rooms is to provide structural support, shelter, and protection for nonsafety-related equipment housed within, and to maintain their structural integrity to ensure that they will not adversely affect the components housed within, or the auxiliary building, from' performing their intended functions. 2-84 LRA Table 2.4-2 identifies the components subject to an AMR for the auxiliary building by component type and intended function.2.4.2.2 Staff Evaluation The staff reviewed LRA Section 2.4.2 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.During its review of the LRA Section 2.4.2, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results for the auxiliary building.In RAI 2.4.2-1, dated August 22, 2008, the staff requested that the applicant provide additional information to confirm the inclusion or justify the exclusion of a UFSAR-referenced flood gate separating the auxiliary building from the turbine building with respect to the scope of license renewal.In its response to the RAI, dated September 19, 2008, the applicant stated that the flood gate was in scope for license renewal and subject to an AMR. The response stated that the flood gate was classified under the title "bulkhead" in Table 2.4-2 and that the intended function for the bulkhead entry in Table 2.4-2 is listed as "flood barrier." Based on its review, the staff finds the response to RAI 2.4.2-1 acceptable because the bulkhead component that bears the intended function of flood barrier includes the UFSAR-referenced flood gate; it has been designated as in scope for license renewal, and it is subject to an AMR. The staffs concern described in RAI 2.4.2-1 is resolved.In RAI 2.4.0-1, dated August 22, 2008, the staff requested that the applicant provide additional information, to confirm the component identified as "steelcomponents: all structural steel" in various tables in LRA Section 2.4 includes the connection components (gusset plates, welds, bolts, etc.).In its response to the RAI, dated September 19, 2008, the applicant stated that the connection components (e.g., gusset plates, welds, etc.) for in-scope license renewal SSCs are in scope and subject to an AMR.Based on its review, the staff finds the response to RAI 2.4.0-1 acceptable because the applicant confirmed that all connection components are in scope and subject to an AMR. The staff's concern described in RAI 2.4.0-1 is resolved.In RAI 2.2-1, dated August 22, 2008, the staff requested that the applicant provide additional information to confirm the inclusion or justify the exclusion of the class I chemical cleaning building basin with respect to the scope of license renewal.In its response to the RAI, dated September 19, 2008, the applicant stated that the chemical cleaning building basin had been designed according to class I criteria, but it did not meet any of the scoping criteria of 10 CFR 54.4(a). The applicant stated that the class I criteria was selected due to the chemical cleaning building basin's function to support the processing of low-level, liquid radioactive waste. For this reason, the applicant found the chemical cleaning building basin to be excluded from the scope of license renewal.2-85 LRA Table 2.4-2 identifies the components subject to an AMR for the auxiliary building by component type and intended function. 2.4.2.2 Staff Evaluation The staff reviewed LRA Section 2.4.2 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4. During its review of the LRA Section 2.4.2, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening . results* for the auxiliary building. In RAI 2.4.2-1, dated August 22, 2008, the staff requested that the applicant provide additional information to confirm the inclusion or justify the exclusion of a UFSAR-referenced flood gate separating the auxiliary building from the turbine building with respect to the scope of license renewal. In its response to the RAI, dated September 19, 2008, the applicant stated that the flood gate was in scope for license renewal and subject to an AMR. The response stated that the flood gate was classified under the title "bulkhead" in Table 2.4-2 and that the intended function for the bulkhead entry in Table 2.4-2 is listed as "flood barrier." Based on its review, the staff finds the response to RAI 2.4.2-1 acceptable because the bulkhead component that bears the intended function of flood barrier includes the UFSAR-referenced flood gate; it has been designated as in scope for license renewal, and it is subject to an AMR. The staffs concern described in RAI 2.4.2-1 is resolved. In RAI 2.4.0-1, dated August 22, 2008, the staff requested that the applicant provide additional information, to-c;:onfirmthe cOITlPonentidentified as "steel-components: all structural steel" in various tables in LRA Section 2.4 includes the connection components (gusset plates, welds, bolts, etc.). In its response to the RAI, dated September 19, 2008, the applicant stated that the connection components (e.g., gusset plates, welds, etc.) for in-scope license renewal SSCs are in scope and subject to an AMR. . Based on its review, the staff finds the response to RAI 2.4.0-1 acceptable because the applicant confirmed that all connection components are in scope and subject to an AMR. The staff's concern described in RAJ 2.4.0-1 is resolved. In RAI2.2-1, dated August 22, 2008, the staff requested that the applicant provide additional information to confirm the inclusion or justify the exclusion of the class I chemical cleaning building basin with respect to the scope of license renewal. In its response to the RAI, dated September 19,2008, the applicant stated that the chemical cleaning building basin had been designed according to class I criteria, but it did not meet any of the scoping criteria of 10 CFR 54.4(a). The applicant stated that the class I criteria was selected due to the chemical cleaning building basin's function to support the processing of low-level, liquid radioactive waste. For this reason, the applicant found the chemical cleaning building basin to be excluded from the scope of license renewal. 2-85 Based on its review, the staff finds the response to RAI 2.2-1 acceptable because the CLB of the applicant does not define the chemical cleaning building basin as a safety-related component per 10 CFR 54.4(a)(1), nor would its failure prevent the fulfillment of a safety-related SSC per 10 CFR 54.4(a)(2), nor is it relied upon to fulfill a regulatory function in accordance with 10 CFR 54.4(a)(3). The staff's concern described in RAI 2.2-1 is resolved.2.4.2.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI responses to determine whether the applicant failed to identify any SSCs in scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the auxiliary building SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.4.3 Circulating

Water Pump House 2.4.3.1 Summary of Technical Information in the Application LRA Section 2.4.3 describes the circulating water pump house which includes the circulating water pump house, the circulating water flume canal and intake tunnel. The circulating water pump house is a class III structure located west of and between the Unit 1 cooling towers approximately 700 feet northeast of the Unit 1 reactor building.The circulating water pump house consists of a below grade reinforced portion and an above grade steel superstructure enclosed with insulated aluminum siding. The building contains six circulating water pumps arranged so that three pumps discharge through each of the two 102-inch diameter pipes.The circulating water flume canal and tunnel are reinforced concrete structures that are used to convey water from the cooling tower basins to the Circulating Water Pump House.The purpose of the circulating water pump house is to provide structural support, and shelter and protection for the circulating water pumps which are required to provide the necessary cooling water to the turbine condenser to maintain condenser vacuum. Condenser vacuum is credited for the steam generator tube failure accident and the rod ejection accident as described in Chapter 14 of the UFSAR. Additionally, the diesel driven circulating water flume fire pump required for 10CFR 50.48 is located within the circulating water pump house and draws suction from the ýýcirculating water flume canal. The pump house provides structural support, and shelter and'protection for this diesel fire pump. LRA Table 2.4-3 identifies the components subject to aging management review for the circulating water pump house by component type and intended function.2.4.3.2 Conclusion The staff followed the evaluation methodology discussed in Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately 2-86 Based on its review, the staff finds the response to RAI 2.2-1 acceptable because the CLB of the applicant does not define the chemical cleaning building basin as a safety-related component per 10 CFR 54.4( a)( 1), nor would its failure prevent the fulfillment of a safety-related SSC per 10 CFR 54.4(a)(2), nor is it relied upon to fulfill a regulatory function in accordance with 10 CFR 54.4(a)(3). The staff's concern described in RAI 2.2-1 is resolved. 2.4.2.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI responses to determine whether the applicant failed to identify any SSCs in scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the auxiliary building SCs within the scope of license rerilewal, 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 Circulating

Water Pump House 2.4.3.1 Summary of Technical Information in the Application LRA Section 2.4.3 describes the circulating water pump house which includes the circulating water pump house, the circulating water flume canal and intake tunnel. The circulating water pump house is a class III structure located west of and between the Unit 1 cooling towers ' , approximately 700 feet northeast of the Unit 1 reactor building. The circulating water pump house consists of a below grade reinforced portion and an above grade steel superstructure enclosed with insulated aluminum siding. The building contains six circulating water pumps arranged so that three pumps discharge through each of the two. 102-inch diameter pipes. The Circulating water flume canal and tunnel are reinforced concrete structures that are used to convey water from the cooling tower basins to the Circulating Water Pump House. . The purpose of the circulating water pump house is to provide structural support, and'shelter and protection for the Circulating water pumps which are required to provide the necessary cooli,ng I water to the turbine condenser to maintain condenser vacuum. Condenser vacuum is credited for the steam generator tube failure accident and the rod ejection accident as described in Chapter 14 of the UFSAR Additionally, the diesel driven circulating water flume fire pump required for 10 CFR 50.48 is located within the circulating water pump house and draws suction from the ii circulating water flume canal. The pump house provides structural support, and shelter and! protection for this diesel fire pump. LRA Table 2.4-3 identifies the components subject to aging management review for the Circulating water pump house by component type and intended function. 2.4.3.2 Conclusion The staff followed the evaluation methodology discussed in Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately 2-86 identified the circulating water pump house SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.4.4 Control

Building 2.4.4.1 Summary of Technical Information in the Application LRA Section 2.4.4 describes the control building which is a seismic class I multi-story reinforced concrete structure located southeast of the reactor building, east of the fuel handling building, and west of the turbine building.The building is designed to withstand the effects of normal operating loads and design basisaccident loads, which include the effects of tornado loads, including tornado missiles, flooding, earthquakes, aircraft impact, and equipment-generated missiles.The purpose of the building is to provide structural support, shelter, and protection for vitalmechanical and electrical equipment required for safe operation of the plant, including safe shutdown of the reactor. The building provides structural support and shelter and protection for the control room, which is the main operation center for the plant. The building houses safety-related electrical and mechanical equipment and components, such as the cable spreading room, essential DC batteries, electrical inverters, electrical switchgear, miscellaneous electrical equipment, components and their enclosures, instrumentation and their enclosures as applicable, and control room and control building HVAC. The control building also provides shielding from post-accident radiation exposure to allow personnel access for operating and maintaining equipment. LRA Table 2.4-4 identifies the components subject to an AMR for the control building by component type and intended function.2.4.4.2 Staff Evaluation The staff reviewed LRA Section 2.4.4 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.During its review of the LRA Section 2.4.4, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results for the control building.In RAI 2.4.4-1, dated August 22, 2008, the staff requested that the applicant provide additional information to confirm the inclusion, or justify the exclusion, of a UFSAR-referenced flood gate separating the control building from the turbine building with respect to the scope of license renewal.In its response to the RAI, dated September 19, 2008, the applicant stated that the flood gate was in scope for license renewal and subject to an AMR. The response stated the flood gate was classified under the title "Metal Components: All Structural Members" in Table 2.4-4. The intended function for this component entry in Table 2.4.4 is listed as flood barrier.Based on its review, the staff finds the response to RAI 2.4.4-1 acceptable because the "metal components" entry, which bears the intended function of flood barrier, includes the 2-87 identified the circulating water pump house SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.4.4 Control

Building 2.4.4.1 Summary of Technical Information in the Application LRA Section 2.4.4 describes the control building which is a seismic class I multi-story reinforced concrete structure located southeast of the reactor building, east of the fuel handling building, and west of the turbine building . . The building is designed to withstand the effects of normal operating loads and design basis accident loads, which include the effects of tornado loads, including tornado missiles, flooding, earthquakes, aircraft impact, and equipment-generated missiles. The purpose of the building is to provide structural support, shelter, and protection for vital mechanical and electrical equipment required for safe operation of the plant, including safe shutdown of the reactor. The building provides structural support and shelter and protection for the control room, which is the main operation center for the plant. The building houses safety-related electrical and mechanical equipment and components, such as the cable spreading room, essential DC batteries, electrical inverters, electrical switchgear, miscellaneous electrical equipment, components and their enclosures, instrumentation and their enclosures as applicable, and control room and control building HVAC. The control building also provides shielding from . post-accident radiation exposure to allow personnel access for operating and maintaining equipment. LRA Table 2.4-4 identifies the components subject to an AMR for the control building by component type and intended function. 2.4.4.2 Staff Evaluation The staff reviewed LRA Section 2.4.4 using the evaluation methodology described in SER Sectio"n 2.4 and the guidance in SRP-LR Section 2.4. During its review of the LRA Section 2.4.4, the staff identified areas in which additional information was necessary to complete the evaluation ofthe applicant's scoping and screening results for the control building. . . In RAI 2.4.4-1, dated August 22, 2008, the staff requested that the applicant provide additional information to confirm the inclusion, or justify the excluSion, of a UFSAR-referenced flood gate separating the control building from the turbine building with respect to the scope of license renewal. In its response to the RAI, dated September 19, 2008, the applicant stated that the flood gate was in scope for license renewal and subject to an AMR. The response stated the flood gate was classified under the title "Metal Components: All Structural Members" in Table 2.4-4. The intended function for this component entry in Table 2.4.4 is listed as flood barrier. Based on its review, the staff finds the response to RAI 2.4.4-1 acceptable because the "metal components" entry, which bears the intended function of flood barrier, includes the 2-87 UFSAR-referenced flood gate; it has been designated as in scope for license renewal, and it is subject to an AMR. The staff's concern described in RAI 2.4.4-1 is resolved.2.4.4.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI responses to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the control building SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.4.5 Diesel

Generator Building 2.4.5.1 Summary of Technical Information in the Application LRA Section 2.4.5 describes the diesel generator building which is a single-story, above-grade, reinforced concrete structure, located adjacent to the north wall of the intermediate buildingll and west of the service building.The building is a seismic class I structure designed to withstand the effects of normal operatingloads and design basis accident loads which include tornado loads, tornado missiles, flooding, earthquakes, and equipment-generated missiles.The building houses the safety-related emergency diesel generators, the diesel fuel oil day itanks, electrical and mechanical equipment associated with operation of the diesel generators, and other safety-related and nonsafety-related components. The building is divided into two equal rooms for each diesel generator by an east-west wall. Openings in the roof allow exhaust air to exit the building. The exhaust mufflers for each of the diesel generators are enclosed on the roof of the building within a structural steel frame on a thickened portion of the reinforced concrete roof slab.The purpose of the building is to provide structural support, shelter, and protection for vital mechanical and electrical equipment required for safe operation of the plant, including safe!!shutdown of the reactor. The building also provides shielding from post-accident radiation exposure to allow personnel access for operating and maintaining the diesel generators. LRA Table 2.4-5 identifies the components subject to an AMR for the diesel generator building by component type and intended function.2.4.5.2 Staff Evaluation The staff reviewed LRA Section 2.4.5 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.During its review of the LRA Section 2.4.5, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results for the diesel generator building.2-88 UFSAR-referenced flood gate; it has been designated as in scope for license renewal, and it is subject to an AMR. The staff's concern described in RAI 2.4.4-1 is resolved. 2.4.4.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI responses to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the control building SCs within the scope of license: renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.4.5 Diesel

Generator Building 2.4.5.1 Summary of Technical Information in the Application LRA Section 2.4.5 describes the diesel generator building which is a single-story, above-grade, reinforced concrete structure, located adjacent to the north wall of the intermediate building: and west of the service building. The building is a seismic class I structure designed to withstand the effects of normal operating loads and design basis accident loads which include tornado loads, tornado missiles, flooding, earthquakes, and equipment-generated missiles. The building houses the safety-related emergency diesel generators, the diesel fuel oil daylitanks, electrical and mechanical equipment associated with operation of the diesel generators, other safety-related and nonsafety-related components. The building is divided into two equal rooms for each diesel generator by an east-west wall. Openings in the roof allow exhaust air to exit the building. The exhaust mufflers for each of the diesel generators are enclosed on the roof of the building. within a structural steel frame on a thickened portion of the reinforced concrete roof slab. The purpose of the building is to provide structural support, shelter, and protection for vital ;, mechanical and electrical equipment required for safe operation of the plant, including safe I! shutdown of the reactor. The building also provides shielding from post-accident radiation .. exposure to allow personnel access for operating and maintaining the diesel generators. LRA Table 2.4-5 identifies the components subject to an AMR for the diesel generator building by component type and intended function. 2.4.5.2 Staff Evaluation The staff reviewed LRA Section 2.4.5 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4. During its review of the LRA Section 2.4.5, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results for the diesel generator building. 2-88 In RAI 2.4.5-1, dated August 22, 2008, the staff requested that the applicant provide additionalinformation to confirm the inclusion or justify the exclusion of the UFSAR-referenced flood gates at elevation 305' with respect to the scope of license renewal.In its response to the RAI, dated September 19, 2008, the applicant stated that the flood gates were in scope for license renewal and subject to an AMR. The response stated that the flood gate was classified under the title "Metal Components: All Structural Members" in Table 2.4-5. The intended function for this component entry in Table 2.4-5 is listed as "flood barrier." The staff finds the response to RAI 2.4.5-1 acceptable because the "metal components" entry, which bears the intended function of flood barrier, includes the UFSAR-referenced flood gates; it has been designated as in scope for license renewal, and it is subject to an AMR. The staff's concern described in RAI 2.4.5-1 is resolved.During its review of Section 2.4-5 of the LRA, the staff noted that steel panels were installed on the diesel generator building to protect the equipment from potential tornado missiles. However, Table 2.4-5 did not include "missile barrier" as an intended function of the building's structural steel. In RAI 2.4.5-2, dated August 22, 2008, the staff requested that the applicant provide additional information to address the absence of the intended function "missile protection" from Table 2.4-5.In its response to the RAI, dated September 19, 2008, the applicant stated that the intended function of missile barrier should have been included in Tables 2.4-5 and 3.5.2-5. The intended function was added and the AMR information was updated.Based on its review, the staff finds the response to RAI 2.4.5-2 acceptable because the intended function of missile barrier has been added to the appropriate LRA tables. The staffs concern described in RAI 2.4.5-2 is resolved.2.4.5.3 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. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the diesel generator building SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1). 2.4.6 Dike/Flood Control System 2.4.6.1 Summary of Technical Information in the Application LRA Section 2.4.6 describes the dike/flood control system which consists of protective dikes and a storm drainage and flood control structure that protects the site from floods from the river.The dikes are nonsafety-related earth embankments, constructed of clay and silt and are protected by rip-rap and sand and gravel embedment material to withstand wave action and a velocity in excess of 12.0 ft/sec, on a 2-on-1 slope.Included within the east side dike is the nonsafety-related reinforced concrete storm drainage and flood control structure that penetrates the dike. Storm water collects in the earthen basin for this 2-89 In RAI 2.4.5-1, dated August 22, 2008, the staff requested that the applicant provide additional information to confirm the inclusion or justify the exclusion of the UFSAR-referenced flood gates at elevation 305' with respect to the scope of license renewal. In its response to the RAI, dated September 19, 2008, the applicant stated that the flood gates were in scope for license renewal and subject to an AMR. The response stated that the flood gate was classified under the title "Metal Components: All Structural Members" in Table 2.4-5. The intended function for this component entry in Table 2.4-5 is listed as "flood barrier." The staff finds the response to RAI 2.4.5-1 acceptable because the "metal components" entry, which bears the intended function of flood barrier, includes the UFSAR-referenced flood gates; it has been designated as in scope for license renewal, and it.is subject to an AMR. The staff's concern described in RAI 2.4.5-1 is resolved. During its review of Section 2.4-5 of the LRA, the staff noted that steel panels were installed on the diesel generator building to protect the equipment from potential tornado missiles. However, Table 2.4-5 did not include "missile barrier" as an intended function of the building's structural steel. In RAI 2.4.5-2, dated August 22, 2008, the staff requested that the applicant provide additional information to address the absence of the intended function "missile protection" from Table 2.4-5. In its response to the RAI, dated September 19, 2008, the applicant stated that the intended function of missile barrier should have been included in Tables 2.4-5 and 3.5.2-5. The intended function was added and the AMR information was updated. Based on its review, the staff finds the response to RAI 2.4.5-2 acceptable because the intended function of missile barrier has been added to the appropriate LRA tables. The staff's concern* described in RAI 2.4.5-2 is resolved. 2.4.5.3 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..The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the diesel generator building SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1). 2.4.6 Dike/Flood Control System 2.4.6.1 Summary of Technical Information in the Application LRA Section 2.4.6 describes the dike/flood control system which consists of protective dikes and a storm drainage and flood control structure that protects the site from floods from the river. The dikes are nonsafety-related earth embankments, constructed of clay and silt and are protected by rip-rap and sand and gravel embedment material to withstand wave action and a velocity in excess of 12.0 ft/sec, on a 2-on-1 slope. Included within the east side dike is the nonsafety-related reinforced concrete storm drainage and flood control structure that penetrates the dike. Storm water collects in the earthen basin for this 2-89 structure on the inboard side of the dike. Influent and effluent reinforced concrete headwalls on the inboard and outboard sides of the dike are connected with a below grade corrugated metal pipe (CMP). Water collected in the earthen basin is drained to the river after sampling during normal river flows. This structure also contains a sluice gate and associated operator supportedby a structural steel platform on the inboard side of the dike. The sluice gate allows storm water collected in the earthen basin to be sampled prior to discharge to the river.The purpose of the dike/flood control system is to provide protection for the site structures and equipment for a design flood of 304'-0".LRA Table 2.4-6 identifies the components subject to an AMR for the dike/flood control system by component type and intended function.2.4.6.2 Staff Evaluation The staff reviewed LRA Section 2.4.6 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.During its review of the LRA Section 2.4.6, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results for the dike/flood control system.In RAI 2.4.6-1, dated August 22, 2008, the staff requested that the applicant provide additional information and confirm the inclusion'or justify the exclusion of a structural steel platform associated with the support of the in-scope sluice gate and operator of the dike/flood control system.In its response to the RAI, dated September 19, 2008, the applicant stated the structural steel platform was in-scope for license renewal and subject to an AMR. The applicant further stated that Section 2.4.6 of the LRA was modified to explicitly specify the inclusion of the platform.Tables 2.4-6 and 3.5.2-6 were both revised to address the steel platform.Based on its review, the staff finds the response to RAI 2.4.6-1 acceptable because the structural steel platform has been included in the scope of license renewal, and the appropriate LRA tables have been revised accordingly. The staff's concern described in RAI 2.4.6-1 is considered resolved.In RAI 2.4.6-2, dated November 24, 2008, the staff noted that on license renewal drawing LR-1 E-120-01-001, the storm drainage and flood control structure is shown outlined in black, indicating that the structure is not within the scope of license renewal. In LRA Section 2.4.6, "dike/flood control system," the applicant stated that the dike/flood control system is in scope under 10 CFR 54.4(a)(2) and, since it was identified as being in scope of license renewal, it should be highlighted as such on the license renewal drawing. The staff requested that the applicant provide additional information to justify the exclusion of the storm drainage and flood control structure from the scope of license renewal on the license renewal drawing.In its response to the RAI, dated December 5, 2008, the applicant stated that the storm drainage and flood control structure is in scope for license renewal under 10 CFR 54.4(a)(2) as indicated in LRA Section 2.4.6, "dike/flood control system," and that license renewal drawing LR-1E-120 001 at location G-4 should have shown the storm drainage and flood control structure outlined in green, indicating that the structure is in scope for license renewal.2-90 structure on the inboard side of the dike. Influent and effluent reinforced concrete headwalls on the inboard and outboard sides of the dike are connected with a below grade corrugated metal pipe (CMP). Water collected in the earthen basin is drained to the river after sampling during normal river flows. This structure also contains a sluice gate and associated operator supported by a structural steel platform on the inboard side of the dike. The sluice gate allows storm water collected in the earthen basin to be sampled prior to discharge to the river. The purpose of the dike/flood control system is to provide protection for the site structures and equipment for a design flood of 304'-0". LRA Table 2.4-6 identifies the components subject to an AMR for the dike/flood control system by component type and intended function. . . 2.4.6.2 Staff Evaluation . The staff reviewed LRA Section 2A.6 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4. During its review of the LRA Section 2.4.6, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and scree/"ling results for the dike/flood control system. , In RAI 2.4.6-1, dated August 22, 2008, the staff requested that the applicant provide additional information and confirm the inclusion* or justify the exclusion of a structural steel platform '! associated with the support of the in-scope sluice gate and operator of the dikelflood control system. ., In its response to the RAI, dated September 19,2008, the applicant stated the structural steel platform was in-scope for license renewal and subject to an AMR. The applicant further stated that Section 2.4.6 of the LRA was modified to explicitly specify the inclusion of the platform. Tables 2.4-6 and 3.5.2-6 were both revised to address the steel platform. Based on its review, the staff finds the response to RAJ 2.4.6-1 acceptable because the structural steel platform.has been included in the scope of license renewal, and the appropriate LRA tables have been revised accordingly. The staff's concern described in RAI 2.4.6-1 is considered resolved. In RAI 2.4.6-2, dated November 24,2008, the staff noted that on license renewal drawing LR-1 E-120-01-001, the storm drainage and flood control structure is shown outlined in black, indicating that the structure is not within the scope of license renewal. In LRA Section 2.4.6, "dike/flood control system," the applicant stated that the dike/flood control system is in scope under 1 0 CFR 54.4(a)(2) and, since it was identified as being in scope of license renewal, it should be highlighted as such on the license renewal drawing. The staff requested that the applicant wovide additional information to justify the exclusion of the storm drainage and flood control structure from the scope of license renewal on the license renewal drawing. In its response to the RAI, dated December 5,2008, the applicant stated that the storm drai'nage and flood control structure is in scope for license renewal under 10 CFR 54.4(a)(2) as in LRA Section 2.4.6, "dikelflood control system," and that license renewal drawing LR-1E-12Q 001 at location G-4 should have shown the storm drainage and flood control structure outlined in green, indicating that the structure is in scope for license renewal. . 2-90 Based on its review, the staff finds the response to RAI 2.4.6-2 acceptable because the applicant indicated that the Storm Drainage and Flood Control Structure is in scope for license renewal and the storm drainage and flood control structure on the drawing should have been outlined in green indicating that the structure is in scope for license renewal. The staffs concern described in RAI 2.4.6-2 is considered resolved.2.4.6.3 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. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the Dike/Flood Control System 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). 2.4.7 Fuel Handling Building 2.4.7.1 Summary of Technical Information in the Application LRA Section 2.4.7 describes the fuel handling buildings which are multi story reinforced concrete structures with three stories above grade and with below grade basements. The Unit 1 fuel handling building is located south of and adjacent to the reactor building.The fuel handling building contains the spent fuel pools, spent fuel cooling pumps and coolers, and new fuel storage vault. Two fuel transfer tubes in the reactor building penetrate the north fuel handling building wall that allow for fuel movement between the fuel transfer canal in the reactor building and the spent fuel storage pool in the fuel handling building. The tubes contain tracks for the fuel transfer carriages, gate valves on the fuel handling building side, and a flanged closure on the reactor building side.The Unit 2 fuel handling building is located south of and adjacent to the Unit 1 fuel handling building. Both buildings share a common area above elevation 348'-0" and the fuel handling building truck bay. The buildings are maintained at a negative pressure with respect to the outside environment by the fuel handling building normal ventilation system (FHBNVS) during normal operations and by the fuel handling building engineered safety feature ventilation system (FHBESFVS) during movement of irradiated fuel.The Unit 1 Fuel Handling Building is a seismic class I structure and is designed for normal operating loads and also to withstand the effects of design basis accident loads as applicable, which include the effects of tornado loads including tornado missiles, flooding, earthquake, aircraft impact and equipment generated missiles. The Unit 2 fuel handling building is required to withstand the effects of tornado loads including tornado missiles and aircraft impact to protect the south end of the Unit 1 fuel handling building.The purpose of the fuel handling buildings is to provide structural support, shelter and protection for the spent fuel cooling pumps, new and spent fuel storage racks, spent fuel pools and electrical and mechanical equipment required for safe operation of the plant, including safe shutdown of the reactor. The Unit 1 fuel handling building also provides shielding from post accident radiation exposure to allow personnel access for operating and maintaining equipment. 2-91 Based on its review, the staff finds the response to RAI 2.4.6-2 acceptable because the applicant indicated that the Storm Drainage and Flood Control Structure is in scope for license renewal and the storm drainage and flood control structure on the drawing should have been outlined in green indicating that the structure is in scope for license renewal. The staff's concern described in RAI 2.4.6-2 is considered resolved. 2.4.6.3 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. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the Dike/Flood Control System 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). . 2.4.7 Fuel Handling Building 2.4.7.1 Summary of Technical Information in the Application LRA Section 2.4.7 describes the fuel handling buildings which are multi story reinforced concrete structures with three stories above grade and with below grade basements. The Unit 1 fuel handling building is located south of and adjacent to the reactor building. The fuel handling building contains the spent fuel pools, spent fuel cooling pumps and coolers, and new fuel storage vault. Two fuel transfer tubes in the reactor building penetrate the north fuel handling building wall that allow for fuel movement between the fuel transfer canal in the reactor building and the spent fuel storage pool in the fuel handling building. The tubes contain tracks for the fuel transfer carriages, gate valves on the fuel handling building side, and a flanged closure on the reactor building side. The Unit 2 fuel handling building is located south of and adjacent to the Unit 1 fuel handling building. Both buildings share a common area above elevation 348'-0" and the fuel handling building truck bay. The buildings are maintained at a negative pressure with respect to the outside environment by the fuel handling building normal ventilation system (FHBNVS) during normal operations and by the fuel handling building engineered safety feature ventilation system (FHBESFVS) during movement of irradiated fuel. The Unit 1 Fuel Handling Building is a seismic class I structure and is designed for normal operating loads and also to withstand the effects of design basis accident loads as applicable, which include the effects of tornado loads including tornado missiles, flooding, earthquake, aircraft impact and equipment generated missiles. The Unit 2 fuel handling building is required to withstand the effects of tornado loads including tornado missiles and aircraft impact to protect the south end of the Unit 1 fuel handling building. The purpose of the fuel handling buildings is to provide structural support, shelter and protection for the spent fuel cooling pumps, new and spent fuel storage racks, spent fuel pools and electrical and mechanical equipment required for safe operation of the plant, including safe shutdown of the reactor. The Unit 1 fuel handling building also provides shielding from post accident radiation exposure to allow personnel access for operating and maintaining equipment. 2-91 LRA Table 2.4-7 identifies the components subject to an AMR for the Fuel Handling Buildings by component type and intended function.2.4.7.2 Conclusion The staff followed the evaluation methodology discussed in Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the fuel handling building SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.4.8 Intake

Screen and Pump House 2.4.8.1 Summary of Technical Information in the Application LRA Section 2.4.8 describes the intake screen and pump house which includes the intake screen and pump house (ISPH), the intake canal located in the Susquehanna River and the nonsafety-related diesel fire pump house, which is located on the north side of the ISPH.The intake screen and pump house is a seismic class I reinforced concrete structure located west south west -of the reactor building, along the western shoreline. The design of the structure ensures that the pumps remain operable if the site is subject to the maximum flood level. The building is designed to withstand the effects of normal operating loads and design basis accident loads, which include the effects of tornado loads including tornado missiles, flooding, ice jams, earthquake, aircraft impact and equipment generated missiles.The intake canal has been constructed in the Susquehanna River bed's channel to the east of the intake screen and pump house to assure that there is a source of cooling water for the safeoperation and shutdown of the plant.The diesel fire pump house is also a reinforced concrete structure attached to the north wall of the ISPH. The building is designed to withstand the effects of normal operating loads.LRA Table 2.4-8 identifies the components subject to aging management review for the Intake Screen and Pump House by component type and intended function.2.4.8.2 Conclusion The staff followed the evaluation methodology discussed in Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the intake screen and pump house 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). 2-92 LRA Table 2.4-7 identifies the components subject to an AMR for the Fuel Handling Buildings by component type and intended function. 2.4.7.2 Conclusion The staff followed the evaluation methodology discussed in Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the of license renewal. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such; omissions. On the basis of its review, the staff concludes that the applicant has adequately: identified the fuel handling building SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.4.8 Intake

Screen and Pump House 2.4.8.1 Summary of Technical Information in the Application LRA Section 2.4.8 describes the intake screen and pump house which includes the intake screen and pump house (ISPH), the intake canal located in the Susquehanna River and the nonsafety-related diesel fire pump house, which is located on the north side of the ISPH. ' The intake screen and pump house is a seismic class I reinforced concrete structure locate,p west south west of the reactor building, along the western shoreline. The design of the structure' ensures that the pumps remain operable if the site is subject to the maximum flood level. The building is designed to withstand the effects of normal operating loads and design basis accident loads, which include the effects of tornado loads including tornado missiles, flooding, ice jams, earthquake, aircraft impact and equipment generated missiles. The intake canal has been constructed in the Susquehanna River bed's channel to the east of the intake screen and pump house to assure that there is a source of cooling water for the safe operation and shutdown of the plant. The diesel fire pump house is also a reinforced concrete structure attached to the north wall of the ISPH. The building is designed to withstand the effects of normal operating loads. LRA Table 2.4-8 identifies the components subject to aging management review for the Intake Screen and Pump House by component type and intended function. 2.4.8.2 Conclusion The staff followed the evaluation methodology discussed in Section 2.4 and reviewed the l..1RA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such" omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the intake screen and pump house 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). 2-92

2.4.9 Intermediate

Building 2.4.9.1 Summary of Technical Information in the Application LRA Section 2.4.9 describes the intermediate building which includes the seismic class I portion of the building and the class III or nonsafety-related portion of the building.The seismic class I portion of the building is a reinforced concrete multi-story structure above grade with a portion of the structure approximately 10 feet below grade and is located north of and adjacent to the reactor building. The nonsafety-related portion of the building is a multi-story above grade steel framed structure and is located east of and adjacent to the reactor building and west of the heater bay portion of the turbine building.The seismic class I portion of the building contains the class I main steam piping, pumpsand turbines and electrical and mechanical equipment and emergency feedwater piping required for safe operation of the plant, including safe shutdown of the reactor. The nonsafety-related portion of the building contains main steam and class 1 emergency feedwater system piping required for safe operation of the plant, including safe shutdown of the reactor and 480V load centers and switchgear. The seismic class I portion of the building is designed to withstand the effects of normal operating and design basis accident loads which include the effects of tornado loads including tornado missiles, flooding, earthquake and main steam turbine missiles.LRA Table 2.4-9 identifies the components subject to an AMR for the Intermediate Building by component type and intended function.2.4.9.2 Conclusion The staff followed the evaluation methodology discussed in Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope oflicense renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the intermediate building SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1). 2.4.10 Mechanical Draft Cooling Tower Structures 2.4.10.1 Summary of Technical Information in the Application LRA Section 2.4.10 describes the MDCT structures which include the MDCT basin, the intake water shut-off chamber, a building at the south end of the MDCT basin, the foundation and dike for the sodium bisulfate tank, and the discharge structure-bldg. 332. All these structures are Class III and located southwest of the reactor building.The MDCT basin consists of a multi-cell, reinforced concrete box, partly underground and partly above ground. The basin has an adjoining Unit 2 structure on the south end, which does not contain any equipment associated with the operation of Unit 1.2-93 2.4.9 Intermediate Building 2.4.9.1 Summary of Technical Information in the Application LRA Section 2.4.9 describes the intermediate building which includes the seismic class I portion of the building and the class III or nonsafety-related portion of the building. The seismic class I portion of the building is a reinforced concrete multi-story structure above grade with a portion of the structure approximately 10 feet below grade and is located north of and adjacent to the reactor building. The nonsafety-related portion of the building is a multi-story above grade steel framed structure and is located east of and adjacent to the reactor building and west of the heater bay portion of the turbine building. The seismic class I portion of the building contains the class I main steam piping, pumps and turbines and electrical and mechanical equipment and emergency feedwater piping required for safe operation of the plant, including safe shutdown of the reactor. The nonsafety-related portion of the building contains main steam and class 1 emergency feedwater system piping required for safe operation of the plant, including safe shutdown of the reactor and 480V load centers and switchgear. The seismic class I portion of the building is designed to withstand the effects of normal operating and design basis accident loads which include the effects of tornado loads including tornado missiles, flooding, earthquake and main steam turbine missiles. LRA Table 2.4-9 identifies the components subject to an AMR for the Intermediate Building by component type and intended function. 2.4.9.2 Conclusion The staff followed the evaluation methodology discussed in Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the intermediate building SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1). 2.4.10 Mechanical Draft Cooling Tower Structures 2.4.10.1 Summary of Technical Information in the Application LRA Section 2.4.10 describes the MDCT structures which include the MDCT basin, the intake water shut-off chamber, a building at the south end of the MDCT basin, the foundation and dike for the sodium bisulfate tank, and the discharge structure-bldg. 332. All these structures are Class III and located southwest of the reactor building. The MDCT basin consists of a multi-cell, reinforced concrete box, partly underground and partly above ground. The basin has an adjoining Unit 2 structure on the south end, which does not contain any equipment associated with the operation of Unit 1. 2-93 The intake water shut-off chamber is a reinforced concrete box, also partly above ground and partly underground, with steel grating covering the open top.The building at the south end of the MDCT basin consists of reinforced masonry block and concrete walls and a reinforced concrete roof slab. The building currently houses obsolete equipment associated with operation of the MDCT prior to removal of the mechanical draft cooling tower fill.The discharge structure is a reinforced concrete box partly underground and partly above ground.The purpose of the MDCT basin, the intake water shut-off chamber, and the discharge structure is to provide support for the inlet and outlet river discharge piping associated with the safety-related nuclear services and decay heat river water systems. The MDCT basin, including the internal walls, the intake water shut-off chamber, and the discharge structure are also required to maintain their structural integrity to provide a flow path for the inlet and outlet river discharge piping.LRA Table 2.4-10 identifies the components subject to an AMR for the MDCT structures by component type and intended function.2.4.10.2 Staff Evaluation The staff reviewed LRA Section 2.4.10 using the evaluation methodology described in SERSection 2.4 and the guidance in SRP-LR Section 2.4.During its review of the LRA Section 2.4.10, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results for the MDCT structures. In RAI 2.4.10-1, dated August 22, 2008, the staff requested that the applicant provide additional information to justify the LRA statement that failure of the out-of-scope MDCT building, adjoining Unit 2 structure, and sodium bisulfate tank foundation and dike would not affect the intended function of the in-scope MDCT basin.In its response to the RAI, dated September 19, 2008, and its supplemental response to the RAI, dated November 3, 2008, the applicant stated that hypothetical failure of the out-of-scope MDCT building, adjoining Unit 2 structure, and sodium bisulfate tank foundation and dike was not part of the CLB.Based on its review, the staff finds the response to RAI 2.4.10-1 acceptable because Section 2.1.3.1.2 of the SRP-LR states that the applicant is required to identify and evaluate only those nonsafety-related SSCs whose failures are considered in the CLB and could prevent the fulfillment of a 10 CFR 54.4(a)(1) safety function. The MDCTs, adjoining Unit 2 structure, and sodium bisulfate tank foundation and dike do not meet these criteria. The staff's concern described in RAI 2.4.10-1 is resolved.2.4.10.3 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. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that 2-94 The intake water shut-off chamber is a reinforced concrete box, also partly above ground and partly underground, with steel grating covering the open top. The building at the south end of the MDCT basin consists of reinforced masonry block and concrete walls and a reinforced concrete roof slab. The building currently houses obsolete . equipment associated with operation of the MDCT prior to removal of the mechanical draft cooling tower fill. The discharge structure is a reinforced concrete box partly underground and partly above ground. The purpose oOhe MDCT basin, the intake water shut-off chamber, and the discharge structure is to provide support for the inlet and outlet river discharge piping associated with the safety-related nuclear services and decay heat river water systems. The MDCT basin, including the internal I walls, the intake water shut-off chamber, and the discharge structure are also required to maintain their structural integrity to provide a flow path for the inlet and outlet river discharge piping. LRA Table 2:4-10 identifies the components subject to an AMR for the MDCT structures by component type and intended function. 2.4.10.2 Staff Evaluation The staff reviewed LRA Section 2.4.10 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4. During its review of the LRA Section 2.4.10, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results for the MDCT structures. In RAI 2.4.10-1, dated August 22, 2008, the staff requested that the applicant provide additional information to justify the LRA statement that failure of the out-of-scope MDCT building, adjoining .. Unit 2 structure, and sodium bisulfate tank foundation and dike would not affect the intended function of the in-scope MDCT basin. In its response to the RAI, dated September 19, 2008, and its supplemental response to the RAI, dated November 3,2008, the applicant stated that hypothetical failure of the out-of-scope MDCT building, adjoining Unit 2 structure, and sodium bisulfate tank foundation and dike was not part of the CLB. Based on its review, the staff finds the response to RAI 2.4.10-1 acceptable because Section 2.1.3.1.2 of the SRP-LR states that the applicant is required to identify and evaluate only those nonsafety-related SSCs whose failures are considered in the CLB and could prevent the fulfillment of a 10 CFR 54.4(a)(1) safety function. The MDCTs, adjoining Unit 2 structure, and sodium bisulfate tank foundation and dike do not meet these criteria. The staff's concern described in RAI 2.4.10-1 is resolved. 2.4.10.3 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. The staff finds no such omi.ssions. In addition, the staffs review determined whether the applicant failed to identify any SCs si:Jbject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that 2-94 the applicant has adequately identified the mechanical draft cooling structures SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1). 2.4.11 Miscellaneous Yard Structures 2.4.11.1 Summary of Technical Information in the Application LRA Section 2.4.11 describes the miscellaneous yard structures which includes the following: (a) condensate storage tank foundation (b) borated water storage tank foundation (c) diesel fuel storage tank foundation (d) altitude tank foundation (e) duct banks and manholes There are two condensate storage tanks and each tank has a 265,000 gallon capacity. One tank is located east of the service building and the other tank is located west of the outage equipment storage building. These tanks provide a source of water for the main and emergency feedwater system and for systems credited for fire protection and SBO.The borated water storage tank provides a source of borated water for the ECCS and the reactor building spray system.The diesel fuel storage tank is a 30,000 gallon capacity tank that provides a source of fuel oil for the EDGs.The altitude tank provides an alternate source of water for the fire suppression system. The tank has a 100,000 gallon capacity and is located approximately 400 feet north of the reactor building.Duct banks are multiple raceways that are encased in reinforced concrete and buried within the soil or compacted backfill. The duct banks' intended functions are to provide structural support and shelter and protection for raceways.Manholes serve as intermediate connection point(s) of duct banks that contain safety-related raceways or support a 10 CFR 54.4 a(2) function for 10 CFR 54.4 a(1) components or contain raceways required for Fire Protection or Station Blackout. Manholes are reinforced concrete boxes (cast in-place or precast) that are buried within the soil or compacted backfill. The manholes provide structural support and shelter and protection for electrical cable or raceway that are used to route the electrical cable.LRA Table 2.4-11 identifies the components subject to an AMR for the miscellaneous yard structures by component type and intended function.2.4.11.2 Conclusion The staff followed the evaluation methodology discussed in Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined 2-95 the applicant has adequately identified the mechanical draft cooling structures SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1). 2.4.11 Miscellaneous Yard Structures 2.4.11.1 Summary of Technical Information in the Application LRA Section 2.4.11 describes the miscellaneous yard structures which includes the following: (a) condensate storage tank foundation (b) borated water storage tank foundation (c) diesel fuel storage tank foundation (d)* altitude tank foundation (e) duct banks and manholes There are two condensate storage tanks and each tank has a 265,000 gallon capacity. One tank is located east of the service building and the other tank is located west of the outage equipment storage building. These tanks provide a source of water for the main and emergency feedwater system and for systems credited forfire protection and SBO. The borated water storage tank provides a source of borated water for the ECCS and the reactor building spray system. The diesel fuel storage tank is a 30,000 gallon capacity tank that provides a source of fuel oil for the EDGs. The altitude tank provides an alternate source of water for the fire suppression system. The tank has a 100,000 gallon capacity and is located approximately 400 feet north of the reactor building. Duct banks are multiple raceways that are encased in reinforced concrete and buried within the soil or compacted backfill. The duct banks' intended functions are to provide structural support and shelter and protection for raceways. Manholes serve as intermediate connection point(s) of duct banks that contain safety-related raceways or support a 10 CFR 54.4 a(2) function for 10 CFR 54.4 a( 1) components or contain raceways required for Fire Protection or Station Blackout. Manholes are reinforced concrete boxes (cast in-place or precast) that are buried within the soil or compacted backfill. The manholes provide structural support and shelter and protection for electrical cable or raceway that are used to route the electrical cable. LRA Table 2.4-11 identifies the components subject to an AMR for the miscellaneous yard structures by component type and intended function. 2.4.11.2 Conclusion The staff followed the evaluation methodology discussed in Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined 2-95 whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the miscellaneous yard structures SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1). 2.4.12 Natural Draft Cooling Towers 2.4.12.1 Summary of Technical Information in the Application LRA Section 2.4.12 describes the natural draft cooling towers, which are classified as Class III structures and include the reinforced concrete hyperbolic towers, the wooden fill structure, the canopy at the base of the towers, and the reinforced concrete basin. The natural draft cooling towers are located approximately 600 feet northeast of the reactor building.The purpose of the reinforced concrete basin of the natural draft cooling towers is to provide a source of water for the circulating water pump house. The diesel fire pump required for 10 CFR 50.48 is located within the circulating water pump house. The diesel fire pump draws suction from the circulating water flume canal and tunnel. Additionally, the circulating water pumps located within the circulating water pump house are required to provide the necessary cooling water to the turbine condenser to maintain condenser vacuum.LRA Table 2.4-12 identifies the components subject to an AMR for the natural draft cooling towers by component type and intended function.2.4.12.2 Staff Evaluation The staff reviewed LRA Section 2.4.12 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.During its review of the LRA Section 2.4.12, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results for the natural draft cooling towers.In RAI 2.4.12-1, dated August 22, 2008, the staff requested that the applicant provide additional information to justify the LRA statement that failure of the out-of-scope reinforced concrete, hyperbolic towers, the wooden fill structure, and the canopy would not affect the intended function of the in-scope reinforced concrete basins.In its response to the RAI, dated September 19, 2008, and its supplemental response to the RAI, dated November 3, 2008, the applicant stated that hypothetical failure of the out-of-scope reinforced concrete hyperbolic towers, the wooden fill structure, and the canopy were not part of the CLB.Based on its review, the staff finds the response to RAI 2.4.12-1 acceptable because Section 2.1.3.1.2 of the SRP-LR states that the applicant is required to identify and evaluate only those nonsafety-related SSCs whose failures are considered in the CLB and could prevent: the fulfillment of a 10 CFR 54.4(a)(1) safety function. The hyperbolic cooling towers, the wooden fill structures, and the canopy do not meet these criteria. The staff's concern in RAI 2.4.12-1 is resolved.2-96 whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the miscellaneous yard structures SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1). 2.4.12 Natural Draft Cooling Towers 2.4.12.1 Summary of Technical Information in the Application LRA Section 2.4.12 describes the natural draft cooling towers, which are classified as Class III structures and include the reinforced concrete hyperbolic towers, the wooden fill structure, the canopy at the base of the towers, and the reinforced concrete basin. The natural draft cooling towers are located approximately 600 feet northeast of the reactor building. The purpose of the reinforced concrete basin of the natural draft cooling towers is to provide a source of water for the Circulating water pump house. The diesel fire pump required for

  • 10 CFR 50.48 is located within the circulating water pump house. The diesel fire pump draJ.,s suction from the circulating water flume canal and tunnel. Additionally, the Circulating water pumps located within the circulating water pump house are required to provide the necessary cooling water to the turbine condenser to maintain condenser vacuum. LRA Table 2.4-12 identifies the components subject to an AMR for the natural draft cooling.towers by component type and intended function.

2.4.12.2 Staff Evaluation The staff reviewed LRA Section 2.4.12 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4. During its review of the LRA Section 2.4.12, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results for the natural draft cooling towers. In RAI 2.4.12-1, dated August 22, 2008, the staff requested that the applicant provide additional information to justify the LRA statement that failure of the out-of-scope reinforced concrete I' hyperbolic towers, the wooden fill structure, and the canopy would not affect the intended function of the in-scope reinforced concrete basins. In its response to the RAI, dated September 19, 2008, and its supplemental response to RAI, dated November 3, 2008, the applicant stated that hypothetical failure of the out-of-scope reinforced concrete hyperbolic towers, the wooden fill structure, and the canopy were not part of the CLB. Based on its review, the staff finds the response to RAI 2.4.12-1 acceptable because Section 2.1.3.1.2 of the SRP-LR states that the applicant is required to identify and evaluate only those nonsafety-related SSCs whose failures are considered in the CLB and could the fulfillment of a 10 CFR 54.4(a)(1) safety function. The hyperbolic cooling towers, the wooden fill structures, and the canopy do not meet these criteria. The staff's concern in RAI 2.4.12-1 is resolved. 2-96 2.4.12.3 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. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the natural draft cooling tower 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). 2.4.13 Structural Commodities 2.4.13.1 Summary of Technical Information in the Application LRA Section 2.4.13 describes the structural commodities which are component groups that share material and environment properties allowing a common program to manage their aging effects.Structural commodities include structural bolting, concrete anchors and embedments, conduit, cable trays, tube track, cabinets, enclosures, racks, frames and panels for electrical equipment and instrumentation, penetration sleeves including end caps, penetration seals, bus ducts, and piping and component insulation. Structural bolting includes bolting which provides structural support for connections associated with structural steel assemblies which are in scope for license renewal.Concrete anchors and embedments (i.e., embedded plates) include expansion and grouted anchor bolts and embedments (including studs) that perform an intended function for structural support for various structural, mechanical and electrical system components and commodities that are in scope for license renewal.Conduit, cable trays, tube track, cabinets, enclosures, racks, frames and panels for electrical equipment and instrumentation in scope for license renewal include those items that provide structural support or shelter and protection for various mechanical and electrical system components and commodities that are in scope for license renewal.Penetration sleeves including end caps and penetration seals in scope for license renewal include those items that perform various license renewal intended functions for shelter and protection, flood barrier, pressure boundary, radiation shielding and HELB shielding for structures that are in scope for license renewal.Bus ducts and associated rain covers in the scope for license renewal include those items that perform a license renewal intended function for shelter and protection for metal enclosed buses that are in scope for license renewal.Piping and component insulation includes the insulation and associated metal jacketing for all piping and components. Piping insulation and component insulation is comprised of prefabricated blankets, modules, or panels engineered as integrated assemblies to fit the surface to be insulated and to fit easily against the piping and components. Metallic insulation consists of stainless steel mirror insulation. Nonmetallic insulation consists of asbestos and light density, semi-rigid fibrous glass (pad) insulation, quilted between two layers of glass scrim and encapsulated in a fiberglass cloth, jackets forming a composite blanket; premolded fiberglass modules and panels encased in fiberglass cloth jackets or calcium silicate. Anti-sweat or freeze 2-97 2.4.12.3 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. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the natural draft cooling tower 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). 2.4.13 Structural Commodities 2.4.13.1 Summary of Technical Information in the Application LRA Section 2.4.13 describes the structural commodities which are component groups that share material and environment properties allowing a common program to manage their aging effects. Structural commodities include'structural bolting, concrete anchors and embedments, conduit, cable trays, tube track, cabinets, enclosures, racks, frames and panels for electrical equipment and instrumentation, penetration sleeves including end caps, penetration seals, bus ducts, and piping and component insulation. Structural bolting includes bolting which provides structural support for connections associated with structural steel assemblies which are in scope for license renewal. Concrete anchors and embedments (Le., embedded plates) include expansion and grouted anchor bolts and embedments (including studs) that perform an intended function for structural support for various structural, mechanical and electrical system components and commodities that are in scope for license renewal. Conduit, cable trays, tube track, cabinets, enclosures, racks, frames and panels for electrical equipment and instrumentation in scope for license renewal include those items that provide structural support or shelter and protection for various mechanical and electrical system components and commodities that are in scope for license renewal. Penetration sleeves including end caps and penetration seals in scope for license renewal include those items that perform various license renewal intended functions for shelter and protection, flood barrier, pressure boundary, radiation shielding and HELB shielding for structures that are in scope for license renewal. Bus ducts and associated rain covers in the scope for license renewal include those items that perform a license renewal intended function for shelter and protection for metal enclosed buses that are in scope for license renewal. Piping and component insulation includes the insulation and associated metal jacketing for all piping and components. Piping insulation and component insulation is comprised of prefabricated blankets, modules, or panels engineered as integrated assemblies to fit the surface to be insulated and to fit easily against the piping and components. Metallic insulation consists of stainless steel mirror insulation. Nonmetallic insulation consists of asbestos and light density, semi-rigid fibrous glass (pad) insulation, quilted between two layers of glass scrim and encapsulated in a fiberglass cloth, jackets forming a composite blanket; premolded fiberglass modules and panels encased in fiberglass cloth jackets or calcium silicate. Anti-sweat or freeze 2-97 protection insulation consists of closed cell, foamed plastic type, cellular glass or fiberglass (inside containment) and fiberglass or mineral wool (outside containment). Metal protective jackets are made from rolled aluminum or stainless steel.The purpose of insulation is to improve thermal efficiency, minimize heat loads on the HVAC systems, provide for personnel protection, or prevent freezing of heat traced piping and sweating of cold piping and components. The insulation jacketing shelters and protects the associated insulation. Insulation is also used to protect penetration concrete in close proximity to hot piping to maintain concrete temperatures within allowable limits.LRA Table 2.4-13 identifies the components subject to an AMR for the Structural Commodities by component type and intended function.2.4.13.2 Conclusion The staff followed the evaluation methodology discussed in Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the structural 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). 2.4.14 Reactor Building 2.4.14.1 Summary of Technical Information in the Application LRA Section 2.4.14 describes the reactor building which is a post-tensioned reinforced concrete structure with a cylindrical wall, a flat foundation mat, and a shallow dome roof that is designed to withstand the effects of design basis accident loads as applicable, which include the effects iof tornado wind, missiles, flooding, earthquakes, LOCA, aircraft impact, and equipment generated missiles.The reactor building contains the fuel transfer canal, which is a reinforced concrete structure lined with a stainless steel plate above the reactor vessel, and filled with borated water for refueling. The south (deep) portion of the fuel transfer canal is normally used for the storage of the reactor vessel internals and plenum assembly.Two fuel transfer tubes in the fuel transfer canal penetrate the south wall of the reactor building and the north wall of the fuel handling building, which allows for fuel movement between the fuel transfer canal and the spent fuel storage pool.The reactor building interior structure consists of the basement floor, intermediate floor, operating floor, reactor cavity, two steam generator compartments, refueling transfer canal, equipment supports, piping supports and pipe-whipping restraints, removable CRDM missile shield, and incore instrumentation trench.In addition, the reactor building includes the following exterior structural features:.annular reinforced concrete tendon access gallery 2-98 protection insulation consists of closed cell, foamed plastic type, cellular glass or fiberglass (inside containment) and fiberglass or mineral wool (outside containment). Metal protective jackets are made from rolled aluminum or stainless steel. The purpose of insulation is to improve thermal efficiency, minimize heat loads on the HVAC systems, provide for personnel protection, or prevent freezing of heat traced piping and sweating of cold piping and components. The insulation jacketing shelters and protects the associated insulation. Insulation is also used to protect penetration concrete in close proximity to hot piping to maintain concrete temperatures within allowable limits. LRA Table 2.4-13 identifies the components subject to ari AMR for the Structural Commodities by component type and intended function. ' 2.4.13.2 Conclusion The staff followed the evaluation methodology discussed in Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such ' omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the struCtural 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). 2.4.14 Reactor Building 2.4.14.1 Summary of Technical Information in the Application LRA Section 2.4.14 describes the reactor building which is a post-tensioned reinforced concrete structure with a cylindrical wall, a flat foundation mat, and a shallow dome roof that is designed to withstand the effects of design basis accident loads as applicable, which include the effectsl:of tornado wind, missiles, flooding, earthquakes, LOCA, aircraft impact, and equipment generated missiles. The reactor building contains the fuel transfer canal, which is a reinforced concrete structure lined with a stainless steel plate above the reactor vessel, and filled with borated water for refueling. The south (deep) portion of the fuel transfer canal is* normally used for the storage of the reactor vessel internals and plenum assembly. Two fuel transfer tubes in the fuel transfer canal penetrate the south wall of the reactor building and the north wall of the fuel handling building, which allows for fuel movement between the fuel transfer canal and the spent fuel storage pool. The reactor building interior structure consists of the basement floor, intermediate floor, operating floor, reactor cavity, two steam generator compartments, refueling transfer canal, equipment supports, piping supports and pipe-whipping restraints, removable CRDM missile shield, arid incore instrumentation trench. In addition, the reactor building includes the following exterior structural features:

  • annular reinforced concrete tendon access gallery 2-98
  • exterior reinforced concrete retaining wall and associated roof* ventilation exhaust stack LRA Table 2.4-14 identifies the components subject to an AMR for the reactor building by component type and intended function.2.4.14.2 Staff Evaluation The staff reviewed LRA Section 2.4.14 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.During its review of the LRA Section 2.4.14, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results for the reactor building.In RAI 2.4.14-1, dated August 22, 2008, the staff requested that the applicant provide additional information and confirm that the inaccessible floor liner plate, including the leak chase system andthe concrete fill slab above this liner, are included in the components listed in Table 2.4-14.

In its response to the RAI, dated September 19, 2008, the applicant stated that the inaccessible floor liner plate is within the scope of license renewal and subject to an AMR and that it has been included in LRA Table 2.4-14 under the component type "steel elements: liner, liner anchors, and integral attachments." The applicant further stated that the concrete fill slab was also within the scope of license renewal and subject to an AMR and was included under the component type"concrete: interior" in LRA Table 2.4-14. The response further stated that the "leak chase system" referred to by the staff is referred to as test channels by the applicant's UFSAR and that the test channels do not perform collection or monitoring functions associated with leakage. The applicant further stated that the test channels were not within the scope of license renewal because they do not perform a 10 CFR 54.4(a) intended function for license renewal. The applicant did state, however, that the fillet welds which attach the test channels to the containment liner are considered integral attachments and included within the scope of license renewal and subject to an AMR under the component type "steel element: liner, liner anchors, and integral attachment." Based on its review, the staff finds the response to RAI 2.4.14-1 acceptable because the test channels, as described by the applicant, do not perform a 10 CFR 54.4(a) intended function for license renewal. Additionally, the fillet weld which forms the containment boundary has been included within the scope of license renewal and is subject to an AMR. The staffs concern described in RAI 2.4.14-1 is resolved.2.4.14.3 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. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the reactor building SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1). 2-99* exterior reinforced concrete retaining wall and associated roof

  • ventilation exhaust stack LRA Table 2.4-14 identifies the components subject to an AMR for the reactor building by component type and intended function.

2.4.14.2 Staff Evaluation The staff reviewed LRA Section 2.4.14 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4. During its review of the LRA Section 2.4.14, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results for the reactor building. In RAI 2.4.14-1, dated August 22, 2008, the staff requested that the applicant provide additional information and confirm that the inaccessible floor liner plate, including the leak chase system and the concrete fill slab above this liner, are included in the components listed in Table 2.4-14. In its response to the RAI, dated September 19, 2008, the applicant stated that the inaccessible floor liner plate is within the scope of license renewal and subject to an AMR and that it has been included in LRA Table 2.4-14 under the component type "steel elements: liner, liner anchors, and integral attachments." The applicant further stated that the concrete fill slab was also within the scope of license renewal and subject to an AMR and was included under the component type "concrete: interior" in LRA Table 2.4-14. The response further stated that the "leak chase system" referred to by the staff is referred to as test channels by the applicant's UFSAR and that the test channels do not perform collection or monitoring functions associated with leakage. The applicant further stated that the test channels were not within the scope of license renewal because they do not perform a 10 CFR 54.4(a) intended function for license renewal. The applicant did state, however, that the fillet welds which attach the test channels to the containment liner are considered integral attachments and included within the scope of license renewal and subject to an AMR under the component type "steel element: liner, liner anchors, and integral attachment." Based on its review, the staff finds the response to RAI 2.4.14-1 acceptable because the test channels, as described by the applicant, do not perform a 10 CFR 54.4(a) intended function for license renewal. Additionally, the fillet weld which forms the containment boundary has been included within the scope of license renewal and is subject to an AMR. The staffs concern described in RAI2.4.14-1 is resolved. 2.4.14.3 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. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the reactor building SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1). 2-99 2.4.15 SBO Diesel Generator Building 2.4.15.1 Summary of Technical Information in the Application LRA Section 2.4.15 describes the SBO diesel generator building which is a single story reinforced concrete structure located adjacent to the west wall of the Unit 2 fuel handling building.The building contains the SBO diesel generator and associated electrical and mechanical equipment rooms, the abandoned Unit 2 "B" diesel generator, and the fuel oil storage tank rooms.The purpose of the building is to provide structural support, shelter and protection for the nonsafety-related SBO diesel generator, the SBO diesel oil storage tank, electrical and mechanical components associated with operation of the SBO diesel generator and other nonsafety-related components. LRA Table 2.4-15 identifies the components subject to an AMR for the SBO diesel generator building by component type and intended function.2.4.15.2 Conclusion The staff followed the evaluation methodology discussed in Section 2.4 and reviewed the L RA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staffs review determinedwhether the applicant failed to identify any SCs subject to an AMR. The staff finds no such , omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the SBO diesel generator building SOs 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). 2.4.16 Service Building 2.4.16.1 Summary of Technical Information in the Application LRA Section 2.4.16 describes the service building, which includes the service building and machine shop, which are class III structures and are designed to withstand the effects of normal operating loads. The service building and machine shop are adjacent to each other and are located northeast of the reactor building and north of the turbine building.The service building is a single-story, above-grade, steel-framed structure. The machine shop is a two-story, above-grade, steel-framed structure. The purpose of the service building is to provide structural support, shelter, and protection for safety-related mechanical components required for safe operation of the plant, including safe shutdown of the reactor. The machine shop also!provides structural support, shelter, and protection for components required for fire protection. LRA Table 2.4-16 identifies the components subject to an AMR for the service building by component type and intended function.2.4.16.2 Staff Evaluation The staff reviewed LRA Section 2.4.16 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.2-100 2.4.15 SBO Diesel Generator Building 2.4.15.1 Summary of Technical Information in the Application lRA Section 2.4.15 describes the SBO diesel generator building which is a single story reinforced concrete structure located adjacent to the west wall of the Unit 2 fuel handling building. I, The building contains the SBO diesel generator and associated electrical and mechanical I' equipment rooms, the abandoned Unit 2 "B" diesel generator, and the fuel oil storage tank tooms. The purpose of the building is to provide structural support, shelter and protection for the nonsafety-related SBO diesel generator, the SBO diesel oil storage tank, electrical and mechanical components associated with operation of the SBO diesel generator and other nonsafety-related components. lRA Table 2.4-15 identifies the components subject to an AMR for the SBO diesel generator building by component type and intended function. 2.4.15.2 Conclusion The staff followed the evaluation methodology discussed in Section 2.4 and reviewed the LRA II and UFSAR to determine whether the applicant failed to identify any SSCs within the of license renewal. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such il omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the SBO diesel generator building SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1). 2.4.16 Service Building 2.4.16.1 Summary of Technical Information in the Application lRA Section 2.4.16 describes the service building, which includes the service building and I machine shop, which are class III structures and are designed to withstand the effects of normal operating loads. The service building and machine shop are adjacent to each other and are located northeast of the reactor building and north of the turbine building. " The service building is a single-story, above-grade, steel-framed structure. The machine shop is a two-story, above-grade, steel-framed structure. The purpose of the service building is to provide structural support, shelter, and protection for safety-related mechanical components required for safe operation of the plant, including safe shutdown of the reactor. The machine shop also'l provides structural support, shelter, and protection for components required for fire protection. lRA Table 2.4-16 identifies the components subject to an AMR for the service building by ; component type and intended function. 2.4.16.2 Staff Evaluation The staff reviewed LRA Section 2.4.16 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4. 2-100 During its review of LRA Section 2.4.16, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results for the service building.In RAI 2.4.16-1, dated August 22, 2008, the staff requested that the applicant provide additional information to clarify two seemingly contradictory statements from the LRA and the UFSAR regarding the service building. The staff noted that the LRA stated that the service building provided support and shelter to "...safety-related mechanical components required for safe operation of the plant, including safe shutdown of the reactor." The staff also noted that Section 5.1.1.3 of the UFSAR lists the service building as a class III structure. By definition noted in the UFSAR, class III SSCs are not related to reactor operation. In its response to the RAI, dated September 19, 2008, the applicant stated that the service building is a class III structure which houses safety-related equipment. By the standard of 10 CFR 54.4(a)(2), the service building is within the scope of license renewal. Furthermore, the need for clarification of the contradictory statements was entered into the Unit 1 corrective action program.Based on its review, the staff finds the response to RAI 2.4.16-1 acceptable because the service building was determined to be within the scope of license renewal as required by 10 CFR 54.4(a)(2). Furthermore, the applicant entered the contradictory statements into its corrective action program for resolution. The staff's concern described in RAI 2.4.16-1 is resolved.In RAI 2.4.16-2, dated August 22, 2008, the staff requested that the applicant provide additional information to confirm that the reinforced concrete circulating water pipe tunnel which provides support for the service building is in the scope of license renewal.In its response to the RAI, dated September 19, 2008, the applicant stated that the pipe tunnel itself was included in Section 2.3.3.3, circulating water system, of the LRA. Specifically, the tunnel was stated to be encompassed in Table 2.3.3-3 under the component type "piping and fittings." The response did indicate, however, that the intended function of "structural support," as inquired by the staff, had been unintentionally omitted from the table. As a result, several sections of the LRA required revision to include this intended function.Based on its review, the staff finds the response to RAI 2.4.16-2 acceptable because the reinforced concrete circulating water pipe tunnel has been included in the scope of license renewal, and the appropriate sections of the LRA have been properly updated to reflect the intended function of "structural support." The staffs concern described in RAI 2.4.16-2 is resolved.2.4.16.3 ConclusionThe staff reviewed the LRA, UFSAR, and RAI responses to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the service building SOs 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 During its review of LRA Section 2.4.16, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results for the service building. In RAI 2.4.16-1, dated August 22, 2008, the staff requested that the applicant provide additional information to clarify two seemingly contradictory statements from the LRA and the UFSAR regarding the service building. The staff noted that the LRA stated that the service building provided support and shelter to " ... safety-related mechanical components required for safe operation of the plant, including safe shutdown of the reactor." The staff also noted that Section 5.1.1.3 of the UFSAR lists the service building as a class III structure. By definition noted in the UFSAR, class III SSCs are not related to reactor operation. In its response to the RAI, dated September 19, 2008, the applicant stated that the service building is a class III structure which houses safety-related equipment. By the standard of 10 CFR 54.4(a)(2), the service building is within the scope of license renewal. Furthermore, the need for clarification of the contradictory statements was entered into the Unit 1 corrective action program. Based on its review, the staff finds the response to RAI2.4.16-1 acceptable because the service building was determined to be within the scope of license renewal as required by 10 CFR 54.4(a)(2). Furthermore, the applicant entered the contradictory statements into its corrective action program for resolution. The staff's concern described in RAI2.4.16-1 is resolved. In RAI 2.4.16-2, dated August 22,2008, the staff requested that the applicant provide additional information to confirm that the reinforced concrete circulating water pipe tunnel which provides support for the service building is in the scope of license renewal. In its response to the RAI, dated September 19,2008, the applicant stated that the pipe tunnel itself was included in Section 2.3.3.3, circulating water system, of the LRA. Specifically, the tunnel was stated to be encompassed in Table 2.3.3-3 under the component type "piping and fittings." The response did indicate, however, that the intended function of "structural support," as inquired by the staff, had been unintentionally omitted from the table. As a result, several sections of the LRA required revision to include this intended function. Based on its review, the staff finds the response to RAI 2.4.16-2 acceptable because the reinforced concrete Circulating water pipe tunnel has been included in the scope of license renewal, and the appropriate sections of the LRA have been properly updated to reflect the intended function of "structural support." The staffs concern described in RAI 2.4.16-2 is resolved. 2.4.16.3 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. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the service building SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1). 2-101 2.4.17 Component Supports Commodity Group 2.4.17.1 Summary of Technical Information in the Application LRA Section 2.4.17 describes the component supports commodity group which consists of structural elements and specialty components designed to transfer the load applied from a SSC to the building structural element or directly to the building foundation. The commodity group is comprised of the following supports:* supports for ASME class 1, 2 and 3 piping and components

  • constant and variable load spring hangers, guides and stops" anchorage of racks, panels, cabinets, and enclosures for electrical equipment and instrumentation
  • supports for cable trays, conduit, HVAC ducts, instrument tubing, non-ASME piping and components
  • supports for emergency diesel generator and HVAC system components
  • supports for platforms, pipe whip restraints, jet impingement shields and masonry walls The purpose of a support is to transfer gravity, thermal, seismic, and other lateral loads imposed on or by a SSC to the supporting building structural element or foundation.

The component support commodity group includes supports for mechanical, electrical and instrumentation systems, components and structures, and supports for SSCs, which are required to restrain or prevent physical interaction with safety-related SSCs.LRA Table 2.4-17 identifies the components subject to an AMR for the component supports commodity group by component type and intended function.2.4.17.2 Conclusion The staff followed the evaluation methodology discussed in Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope! of license renewal. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the component supports commodity group 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). 2.4.18 Substation structures 2.4.18.1 Summary of Technical Information in the Application LRA Section 2.4.18 describes the substation structures, which include the substation relay houseand the structural steel support structures for the two auxiliary transformers and those associated 2-102 2.4.17 Component Supports Commodity Group 2.4.17.1 Summary of Technical Information in the Application LRA Section 2.4.17 describes the component supports commodity group which consists of structural elements and specialty components designed to transfer the load applied from a SSC to the building structural element or directly to the building foundation. The commodity group is comprised of the following supports:

  • supports for ASME class 1, 2 and 3 piping and components
  • constant and variable load spring hangers, guides and stops
  • anchorage of racks, panels, cabinets, and enclosures for electrical equipment and instrumentation
  • supports for cable trays, conduit, HVAC ducts, instrument tubing, non-ASME piping 'and components
  • supports for emergency diesel generator and HVAC system components
  • supports for platforms, pipe whip restraints, jet impingement shields and masonry Wc:llls The purpose of a support is to transfer gravity, thermal, seismic, and other lateral loads imposed on or by a SSC to the supporting building structural element or foundation.

The component support commodity group includes supports for mechanical, electrical and instrumentation systems, components and structures, and supports for SSCs, which are required to restrain or prevent physical interaction with safety-related SSCs. " LRA Table 2.4-17 identifies the components subject to an AMR for the component supports': commodity group by component type and intended function. 2.4.17.2 Conclusion The staff followed the evaluation methodology discussed in Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope! of license renewal. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such '; omissions. On the basis of its review, the staff concludes that the applicant has adequately' identified the component supports commodity group 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). 2.4.18 SUbstation structures 2.4.18.1 Summary of Technical Information in the Application LRA Section 2.4.18 describes the substation structures, which include the substation relay house and the structural steel support structures for the two auxiliary transformers and those assoCiated 2-102 with buses 04 and 08 including the first circuit breakers upstream of the 1A and 1 B Auxiliary and Main Transformers. The substation structures are located east of the turbine building.The substation structures include the substation relay house, the foundations for the auxiliary transformers, and the foundations and miscellaneous structural steel for supporting high voltage insulators, transmission conductors and switchyard bus associated with buses 04 and 08 including the first circuit breakers upstream of the 1 A and 1 B auxiliary and main transformers. The substation relay house is a single story above grade structure with reinforced concrete below grade walls and is located east of the turbine building.LRA Table 2.4-18 identifies the components subject to an AMR for the substation structures by component type and intended function.2.4.18.2 Conclusion The staff followed the evaluation methodology discussed in Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the substation structures SOs 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). 2.4.19 Turbine Building 2.4.19.1 Summary of Technical Information in the Application LRA Section 2.4.19 describes the turbine building which includes the turbine building, heater bay, auxiliary boiler enclosure, and make-up waste neutralizer tank enclosure, which are all class III structures and are designed to withstand the effects of normal operating loads.The turbine building and heater bay are multi-story steel-framed structures. The turbine building contains the turbine generator pedestal. The turbine building and heater bay are located east ofthe reactor building and Class III portion of the intermediate building, and north of the control building.The auxiliary boiler enclosure is single-story, above-grade steel structure attached to the east wall of the turbine building. The make-up waste neutralizer tank enclosure is a single-story above grade steel structure attached to the southwest wall of the turbine building. The buildings included within the turbine building evaluation boundary house electrical and mechanical equipment required for safe operation of the plant, including steam and power conversion system components and supporting systems. Major components within the buildings include the turbine generators, main condensers, condensate pumps, main steam stop and control valves, moisture separators, reactor feedwater pumps, turbine building and heater bay heating and ventilation system, auxiliary boilers, and associated piping and makeup waste neutralizer tank.The purpose of the buildings is to provide structural support, shelter, and protection for mechanical and electrical equipment required for safe operation of the plant, including safe shutdown of the reactor. Additionally, they provide structural support, shelter, and protection for electrical and mechanical equipment required for station blackout, fire protection, and anticipated 2-103 with buses 04 and 08 including the first circuit breakers upstream of the 1 A and 1 B Auxiliary and Main Transformers. The sUbstation structures are located east of the turbine building. The substation structures include the substation relay house, the foundations for the auxiliary transformers, and the foundations and miscellaneous structural steel for supporting high voltage insulators, transmission conductors and switchyard bus associated with buses 04 and 08 including the first circuit breakers upstream of the 1 A and 1 B auxiliary and main transformers. The substation relay house is a single story above grade structure with reinforced concrete below grade walls and is located east of the turbine building. LRA Table 2.4-18 identifies the components subject to an AMR for the substation structures by component type and intended function. 2.4.18.2 Conclusion The staff followed the evaluation methodology discussed in Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the substation 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). 2.4.19 Turbine Building 2.4.19.1 Summary of Technical Information in the Application LRA Section 2.4.19 describes the turbine building which includes the turbine building, heater bay, auxiliary boiler enclosure, and make-up waste neutralizer tank enclosure, which are all class III structures and are designed to withstand the effects of normal operating loads. . The turbine building and heater bay are mUlti-story steel-framed structures. The turbine building contains the turbine generator pedestal. The turbine building and heater bay are located east of the reactor building and Class III portion of the intermediate building, and north of the control building. . The auxiliary boiler enclosure is single-story, above-grade steel structure attached to the east wall of the turbine building. The make-up waste neutralizer tank enclosure is a single-story above grade steel structure attached to the southwest wall of the turbine building. The buildings included within the turbine building evaluation boundary house electrical and mechanical equipment required for safe operation of the plant, including steam and power conversion system components and supporting systems. Major components within the buildings include the turbine generators, main condensers, condensate pumps, main steam stop and control valves, moisture separators, reactor feedwater pumps, turbine building and heater bay heating and ventilation system, auxiliary boilers, and associated piping and makeup waste neutralizer tank. The purpose of the buildings is to provide structural support, shelter, and protection for mechanical and electrical equipment required for safe operation of the plant, including safe shutdown of the reactor. Additionally, they provide structural support, shelter, and protection for electrical and mechanical equipment required for station blackout, fire protection, and anticipated 2-103 transients without scram. The turbine building also provides shielding from post-accident radiation exposure to allow personnel access for operating and maintaining equipment. LRA Table 2.4-19 identifies the components subject to an AMR for the turbine building by component type and intended function.2.4.19.2 Staff Evaluation The staff reviewed LRA Section 2.4.19 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.During its review of the LRA Section 2.4.19, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results for the turbine building.In RAI 2.4.19-1, dated August 22, 2008, the staff requested that the applicant provide additional information to clarify two seemingly contradictory statements from the LRA and the UFSAR regarding the turbine building. The LRA stated that the turbine building provided support and shelter to "...mechanical and electrical equipments required for safe operation of the plant, including safe shutdown of the reactor." Section 5.1.1.3 of the UFSAR lists the turbine building as a class III structure. By definition noted in the UFSAR, class III SSCs are not related to reactor operation. Furthermore, Section 5.4.3.2.5 of the UFSAR states, "There is no equipment located in the turbine building that is required for safe shutdown of the plant." In its response to the RAI, dated September 19, 2008, the applicant stated that the turbine building is a class III structure that houses safety-related equipment. By the standard of 10 CFR 54.4(a)(2), the turbine building is within the scope of license renewal. Furthermore, the need for clarification of the contradictory statements was entered into its corrective action program.Based on its review, the staff finds the response to RAI 2.4.19-1 acceptable because the turbine building was determined to be within the scope of license renewal as required by 10 CFR 54.4(a)(2). Furthermore, the applicant entered the contradictory statements into its corrective action program for resolution. The staff's concern described in RAI 2.4.19-1 is resolved.2.4.19.3 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. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the turbine building SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1). 2.4.20 UPS Diesel Building 2.4.20.1 Summary of Technical Information in the Application LRA Section 2.4.20 describes the UPS diesel building which is a single story above grade steel framed structure located adjacent to the north wall of the service building.2-104 transients without scram. The turbine building also provides shielding from post-accident radiation exposure to allow personnel access for operating and maintaining equipment. LRA Table 2.4-19 identifies the components subject to an AMR for the turbine building by component type and intended function. 2.4.19.2 Staff Evaluation The staff reviewed LRA Section 2.4.19 using the evaluation methodology described in SER . Section 2.4 and the guidance in SRP-LR Section 2.4. During its review of the LRA Section 2.4.19, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results for the turbine building. In RAI 2.4.19-1, dated August 22, 2008, the staff requested that the applicant provide additional information to clarify two seemingly contradictory statements from the LRA and the UFSAR regarding the turbine building. The LRA stated that the turbine building provided support and shelter to " ... mechanical and electrical equipments required for safe operation of the plant, including safe shutdown of the reactor." Section 5.1.1.3 of the UFSAR lists the turbine building as a class III structure. By definition noted in the UFSAR, class III SSCs are not related to reactor operation. Furthermore, Section 5.4.3.2.5 of the UFSAR states, "There is no equipment located in the turbine building that is required for safe shutdown of the plant." In its response to the RAI, dated September 19, 2008, the applicant stated that the turbine building is a class III structure that houses safety-related equipment. By the standard of 10 CFR 54.4(a)(2), the turbine building is within the scope of license renewal. Furthermore, the need for clarification of the contradictory statements was entered into its corrective action program. Based on its review, the staff finds the response to RAI 2.4.19-1 acceptable because the turbine building was determined to be within the scope of license renewal as required by 10 CFR 54.4(a)(2). Furthermore, the applicant entered the contradictory statements into its corrective action program for resolution. The staff's concern described in RAI 2.4.19-1 is resolved. 2.4.19.3 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. The staff finds no such omissions. In addition, the staffs review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the turbine building SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1). 2.4.20 UPS Diesel Building 2.4.20.1 Summary of Technical Information in the Application LRA Section 2.4.20 describes the UPS diesel building which is a single story above grade steel framed structure located adjacent to the north wall of the service building. 2-104 The building houses the security inverter which is required for support of ATWS and also houses the UPS diesel generator and associated electrical and mechanical equipment.The purpose of the building is to provide structural support, shelter and protection for electrical equipment required for ATWS. Additionally, the structure provides structural support, shelter and protection for electrical equipment required for normal plant operations and for electrical and mechanical equipment required to provide back-up power for security. LRA Table 2.4-20 identifiesthe components subject to aging management review for the UPS diesel building by component type and intended function.2.4.20.2 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 finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the UPS diesel building SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.5 Scopina

and Screening Results: Electrical Systems/Commodity Groups This section documents the staffs review of the applicant's scoping and screening results for electrical systems and electrical commodity groups. Specifically, this section describes the following:

  • 2.5.1 Electrical Systems* 2.5.2 Electrical Commodity Groups In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant identified and listed passive, long-lived SCs that are within the scope of license renewal and subject to an AMR. To verify that the applicant properly implemented its methodology, the staff focused its review on the implementation results. This approach allowed the staff to confirm that there were no omissions of electrical system and electrical commodity group components that meet the scoping criteria and are subject to an AMR.The staffs evaluation of the information provided in the LRA was performed in the same manner for all electrical system and electrical commodity group components.

The objective of the review was to determine if electrical system and electrical commodity group components that appeared to meet the scoping criteria specified in the Rule were identified by the applicant as within the scope of license renewal in accordance with 10 CFR 54.4. Similarly, the staff evaluated the applicant's screening results to verify that all long-lived passive components were subject to an AMR in accordance with 10 CFR 54.21(a)(1). To perform its evaluation, the staff reviewed the applicable LRA section and associated drawings, focusing its review 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 system and electrical commodity group component to determine if the applicant had omitted components with intended functions delineated under 10 CFR 54.4(a) from the scope of 2-105 The building houses the security inverter which is required for support of A TWS and also houses the UPS diesel generator and associated electrical and mechanical equipment. The purpose of the building is to provide structural support, shelter and protection for electrical equipment required for ATWS. Additionally, the structure provides structural support, shelter and protection for electrical equipment required for normal plant operations and for electrical and mechanical equipment required to provide back-up power for security. LRA Table 2.4-20 identifies the components subject to aging management review for the UPS diesel building by component type and intended function. 2.4.20.2 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 finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the UPS diesel building SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.5 Scoping

and Screening Results: Electrical Systems/Commodity Groups This section documents the staffs review of the applicant's scoping and screening results for electrical systems and electrical commodity groups. Specifically, this section describes the following:

  • 2.5.1 Electrical Systems
  • 2.5.2 Electrical Commodity Groups In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant identified and listed passive, long-lived SCs that are within the scope of license renewal and subject to an AMR. To verify that the applicant properly implemented its methodology, the staff focused its review on the implementation results. This approach allowed the staff to confirm that there were no omissions of electrical system and electrical commodity group components that meet the scoping criteria and are subject to an AMR. The staffs evaluation of the information provided in the LRA was performed in the same manner for all electrical system and electrical commodity group components.

The objective of the review was to determine if electrical system and electrical commodity group components that appeared to meet the scoping criteria specified in the Rule were identified by the applicant as within the scope of license renewal in accordance with 10 CFR 54.4. Similarly, the staff evaluated the applicant's screening results to verify that all long-lived passive components were subject to an AMR in accordance with 10 CFR 54.21 (a)( 1 ). To perform its evaluation, the staff reviewed the applicable LRA section and associated drawings, focusing its review 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 system and electrical commodity group component to determine if the applicant had omitted components with intended functions delineated under 10 CFR 54.4(a) from the scope of 2-105 license renewal. The staff also reviewed the licensing basis documents to determine if all intended functions delineated under 10 CFR 54.4(a) were specified in the LRA. If omissions were identified, the staff requested additional information to resolve the discrepancies. Once the staff completed its review of the scoping results, the staff evaluated the applicant'sscreening results. For those systems and components with intended functions, the staff sought to determine (1) if the functions are performed with moving parts or a change in configuration or properties, or (2) if they are subject to replacement based on a qualified life or specified time period as described in 10 CFR 54.21(a)(1 ). For those that failed to meet either of these criteria, the staff sought to confirm that these electrical system and electrical commodity group components were subject to an AMR as required by 10 CFR 54.21(a)(1). If discrepancies were identified, the staff requested additional information to resolve them.LRA Section 2.5.2.5 identifies the structures and components of the electrical systems that are subject to an AMR for license renewal.The applicant described the supporting structures and components of the electrical systems in the following sections of the LRA:* 2.5.1.1 120 V Vital Power System* 2.5.1.2 250/125 VDC System* 2.5.1.3 4160 V Auxiliary System* 2.5.1.4 480 V Auxiliary System* 2.5.1.5 6900 V Auxiliary System* 2.5.1.6 Communication System* 2.5.1.7 Digital Turbine Control System* 2.5.1.8 Electrical Heat Tracing System* 2.5.1.9 Engineered Safeguards Actuation System (ESAS)* 2.5.1.10 Heat Sink Protection System* 2.5.1.11 Integrated Control System* 2.5.1.12 Lighting System* 2.5.1.13 Main and Auxiliary Transformers

  • 2.5.1.14 Non-Nuclear Instrumentation and Monitoring System* 2.5.1.15 Nuclear Instrumentation and Incore Monitoring System* 2.5.1.16 Reactor Protection and Control Rod Drive System* 2.5.1.17 Remote Shutdown Panel* 2.5.1.18 Substation In LRA Section 2.5.2, the applicant described the screening process for electrical commodity groups and then described them in the following sections of the LRA:* 2.5.2.5.1 Insulated Cables and Connections
  • 2.5.2.5.2 Metal Enclosed Bus* 2.5.2.5.3 Fuse Holders* 2.5.2.5.4 Cable Connections 2-106 license renewal. The staff also reviewed the licensing basis documents to determine if all intended functions delineated under 10 CFR 54.4(a) were specified in the LRA. If omissions were identified, the staff requested additional information to resolve the discrepancies.

Once the staff completed its review of thescoping results, the staff evaluated the applicant's screening results. For those systems and components with intended functions, the staff sought to determine (1) if the functions are performed with moving parts or a change in configuration or properties, or (2) if they are subject to replacement based on a qualified life or specified time period as described in 10 CFR 54.21(a)(1). For those that failed to meet either of these criteria, the staff sought to confirm that these electrical system and electrical commodity group components were subject to an AMR as required by 10 CFR 54.21(a)(1). If discrepancies were identified, the staff requested additional information to resolve them. " LRA Section 2.5.2.5 identifies the structures and components of the electrical systems that are subject to an AMR for license renewal. The applicant described the supporting structures and components of the electrical in the following sections of the LRA:

  • 2.5.1.1 120 V Vital Power System
  • 2.5.1.2 250/125 VDC System
  • 2.5.1.3 4160 V Auxiliary System
  • 2.5.1.4 480 V Auxiliary System
  • 2.5.1.5 6900 V Auxiliary System
  • 2.5.1.6 Communication System
  • 2.5.1.7 Digital Turbine Control System
  • 2.5.1.8 Electrical Heat Tracing System
  • 2.5.1.9 Engineered Safeguards Actuation System (ESAS)
  • 2.5.1.10 Heat Sink Protection System
  • 2.5.1.11 Integrated Control System
  • 2.5.1.12 Lighting System
  • 2.5.1.13 Main and Auxiliary Transformers
  • 2.5.1.14 Non-Nuclear Instrumentation and Monitoring System
  • 2.5.1.15 Nuclear Instrumentation and Incore Monitoring System
  • 2.5.1.16 Reactor Protection and Control Rod Drive System
  • 2.5.1.17 Remote Shutdown Panel
  • 2.5.1.18 SUbstation In LRA Section 2.5.2, the applicant described the screening process for electrical commodity groups and then described them in the following sections of the LRA:
  • 2.5.2.5.1
  • 2.5.2.5.2
  • 2.5.2.5.3
  • 2.5.2.5.4 Insulated Cables and Connections Metal Enclosed Bus Fuse Holders Cable Connections 2-106
  • 2.5.2.5.5 Connector Contacts for Electrical Connectors Exposed to Borated Water Leakage* 2.5.2.5.6 Electrical Penetrations
  • 2.5.2.5.7 High Voltage Insulators
  • 2.5.2.5.8 Transmissions Conductors and Connections; Switchyard Bus and ConnectionsThe staff's review findings regarding LRA Sections 2.5.1.1-2.5.1.18, and Sections 2.5.2.5.1-2.5.2.5.8 are presented in SER Section 2.5.1.2.5.1 Electrical and Instrumentation and Controls Systems 2.5.1.1 Summary of Technical Information in the Application LRA Section 2.5.1 describes the electrical and I&C systems. The scoping method includes all plant electrical and I&C components. Evaluation of electrical systems includes electrical and I&C components in mechanical systems. The plant spaces approach for the review of plant environments eliminates the need to indicate each unique component and its specific location and precludes improper exclusion of components from an AMR.LRA Table 2.5-1 identifies electrical and I&C systems component types and their intended functions within the scope of license renewal and subject to an AMR:* Cable Connections (Metallic Parts)-Electrical Continuity
  • Connector Contacts for Electrical Connectors Exposed to Borated Water Leakage--Electrical Continuity
  • Fuse Holders-Electrical Continuity
  • High Voltage Insulators-Insulation

/ Electrical

  • Insulated Cables and Connections-Electrical Continuity
  • Insulated Cables and Connections Used in Instrumentation Circuits-Electrical Continuity
  • Insulated Inaccessible Medium Voltage Cables-Electrical Continuity
  • Metal enclosed bus-Electrical Continuity
  • Metal enclosed bus-Insulation

/ Electrical

  • Metal enclosed bus-Shelter/

Protection

  • Switchyard Bus and Connections-Electrical Continuity
  • Transmission Conductors and Connections-Electrical Continuity 2-107* * *
  • 2.5.2.5.5 2.5.2.5.6 2.5.2.5.7 2.5.2.5.8 Connector Contacts for Electrical Connectors Exposed to Borated Water Leakage Electrical Penetrations High Voltage Insulators Transmissions Conductors and Connections; Switchyard Bus and Connections The staff's review findings regarding LRA Sections 2.5.1.1-2.5.1.18, and Sections 2.5.2.5.1-2.5.2.5.8 are presented in SER Section 2.5.1. 2.5.1 Electrical and Instrumentation and Controls Systems 2.5.1.1 Summary of Technical Information in the Application LRA Section 2.5.1 describes the electrical and I&C systems. The scoping method includes all plant electrical and I&C components.

Evaluation of electrical systems includes electrical and I&C components in mechanical systems. The plant spaces approach for the review of plant environments eliminates the need to indicate each unique component and its specific location and precludes improper exclusion of components from an AMR. LRA Table 2.5-1 identifies electrical and I&C systems component types and their intended functions within the scope of license renewal and subject to an AMR:

  • Cable Connections (Metallic Parts)-Electrical Continuity
  • Connector Contacts for Electrical Connectors Exposed to Borated Water Leakage--Electrical Continuity
  • Fuse Holders-Electrical Continuity
  • High Voltage Insulators-Insulation!

Electrical

  • Insulated Cables and Connections-Electrical Continuity
  • Insulated Cables and Connections Used in Instrumentation Circuits-Electrical Continuity
  • Insulated Inaccessible Medium Voltage Cables-Electrical Continuity
  • Metal enclosed bus-Electrical Continuity
  • Metal enclosed bus-Insulation!

Electrical

  • Metal enclosed bus-Shelter!

Protection

  • Switchyard Bus and Connections-Electrical Continuity
  • Transmission Conductors and Connections-Electrical Continuity 2-107 2.5.1.2 Staff Evaluation The staff reviewed LRA Section 2.5 and UFSAR Sections 7 and 8 using the evaluation methodology described in SER Section 2.5 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 has not omitted from the scope of license renewal any components withintended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).

There has been operating experience regarding the failure of cable tie-wraps caused by the age-related brittleness of the plastic material. These cable tie-wraps would be considered long-lived passive components depending on whether or not they have a credited design function.Some possible intended design functions include maintaining spacing for power cable ampacity, maintaining stiffness in unsupported lengths of wire bundles to ensure minimum bending radius, and maintaining cables within vertical raceways. Most recently, at Point Beach, the regional inspectors identified an unresolved item (Inspection Report 05000266/2006006; 05000301/2006006) after noticing that the current configuration of the plant may not be consistent with plant design documents due to the age-related breakage of a large number of plastic tie-wraps used to fasten wires and cables. -At Point Beach, cable tie-wraps are part of the cable design to maintain cable ampacity, or are credited in the applicant's Seismic Qualifications Utility Group documents to seismically qualify the cable tray system.In RAI 2.5.1, dated August 22, 2008, the staff requested that the applicant provide additional information to explain how it manages the aging of cable tie-wraps if they are credited in the plant design basis. In addition, the applicant was to justify why the cable tie-wraps were not included within the scope of license renewal in accordance with the requirements of 10 CFR 54.4.The staff evaluated the LRA, the UFSAR, and the applicant's response to the RAI, dated September 19, 2008 and determined that while tie-wraps are used in cable installations, there are no CLB requirements that cable tie-wraps remain functional during and following DBEs. Cable tie-wraps are not credited for maintaining cable ampacity, ensuring maintenance of cable minimum bending radius, or maintaining cables within vertical raceways. The seismic qualification of cable trays does not credit the use of cable tie-wraps. Cable tie-wraps are not credited in the design basis in terms of any 10 CFR 54.4 intended function. Therefore, cable tie-wraps are not within the scope of license renewal and are therefore not subject to aging management review.The staffs concern described in RAI 2.5.1 is resolved.General Design Criteria 17 of 10 CFR Part 50, Appendix A, requires that electric power from the transmission network to the onsite electric distribution system is supplied by two physically: independent circuits to minimize the likelihood of their simultaneous failure. In addition, the staff noted that the guidance provided by a letter dated April 1, 2002 (ADAMS Accession No. `ML020920464), "Staff Guidance on Scoping of Equipment Relied on to Meet the Requirements of the Station Blackout Rule (10 CFR 50.63) for License Renewal (10 CFR 54.4(a)(3))," and later incorporated in SRP-LR Section 2.5.2.1.1, states: For purposes of the license renewal rule, the staff has determined that the plant system portion of the offsite power system that is used to connect the plant to the offsite power 2-108 2.5.1.2 Staff Evaluation The staff reviewed LRA Section 2.5 and UFSAR Sections 7 and 8 using the evaluation methodology described in SER Section 2.5 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 has not omitted from the scope of license renewal any with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant identified as within the scope of licens.e renewal to verify that the applicant has not omitted any passive and long-lived components subject to an AMR in accordance withthe requirements of 10 CFR 54.21(a)(1). There has been operating experience regarding the failure of cable tie-wraps caused by the age-related brittleness of the plastic material. These cable tie-wraps would be considered long-lived passive components depending on whether or not they have a credited design function. Some possible intended design functions include maintaining spacing for power cable ampacity, maintaining stiffness in unsupported lengths of wire bundles to ensure minimum bending radius, and maintaining cables within vertical raceways. Most recently, at Point Beach, the regional inspectors identified an unresolved item (Inspection Report 05000266/2006006; 05000301/2006006) after noticing that the current configuration of the plant may not be consistent with plant design documents due to the age-related breakage of a large number of plastic tie-wraps used to fasten wires and cables. -At Point Beach, cable tie-wraps are part of the cable design to maintain cable ampacity, or are credited in the applicant's Seismic Qualifications Utility Group documents to seismically qualify the cable tray system. In RAI 2.5.1, dated August 22,2008, the staff requested that the applicant provide additional information to explain how it manages the aging of cable tie-wraps if they are credited in the plant design basis. In addition, the applicant was to justify why the cable tie-wraps were not included within the scope of license renewal in accordance with the requirements of 10 CFR 54.4. The staff evaluated the LRA, the UFSAR, and the applicant's response to the RAI, dated September 19, 2008 and determined that while tie-wraps are used in cable installations, there are no CLB requirements that cable tie-wraps remain functional during and following DBEs. Cable tie-wraps are not credited for maintaining cable ampacity, ensuring maintenance of cable minimum bending radius, or maintaining cables within vertical raceways. The seismic qualification of cable trays does not credit the use of cable tie-wraps. Cable tie-wraps are not credited in the design basis in terms of any 10 CFR 54.4 intended function. Therefore, cable tie-wraps are not within the scope of license renewal and are therefore not subject to aging management re'(iew. The staff's concern described in RAI 2.5.1 is resolved. General Design Criteria 17 of 10 CFR Part 50, Appendix A, requires that electric power from the transmission network to the onsite electric distribution system is supplied by two physically independent circuits to minimize the likelihood of their simultaneous failure. In addition, the staff noted that the guidance provided by a letter dated April 1, 2002 (ADAMS Accession No. .: ML020920464), "Staff Guidance on Scoping of Equipment Relied on to Meet the Requirements of the Station Blackout Rule (10 CFR 50.63) for License Renewal (10 CFR 54.4(a)(3>>," and later incorporated in SRP-LR Section 2.5.2.1.1, states: For purposes of the license renewal rule, the staff has determined that the plant system portion of the offsite power system that is used to connect the plant to the offsite power 2-108 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 SSCs that are part of this circuit path are subject to an AMR will assure that the bases underlying the SBO requirements are maintained over the period of extended license.The applicant includes the complete circuits between the onsite circuits and up to and including the first circuit breakers in the substation (which includes the substation circuit breakers'associated controls and structures) within the scope of license renewal. In Section 2.1.3.4, the applicant states that the boundary between the transmission system and the plant electrical system is the first 230 KV breakers upstream of the 1A and 1 B Auxiliary and Main Transformers. Consequently, the staff concludes that the scoping is consistent with the guidance issued April 1, 2002. This guidance was subsequently incorporated in SRP-LR, Section 2.5.2.1.1. 2.5.1.3 Conclusion The staff reviewed the LRA, the RAI response, and the UFSAR to determine if the applicant failed to identify any SSCs within the scope of license renewal. The staff has found no such omissions. In addition, the staff's review determined whether or not the applicant failed to identify any components subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the electrical and I&C systems components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.6 Conclusion

for Scoping and Screening The staff reviewed the information in LRA Section 2, "Scoping and Screening Methodology for Identifying Structures and Components Subject to Aging Management Review, and Implementation Results." The staff finds that the applicant's scoping and screening methodology is consistent with the requirements of 10 CFR 54.21 (a)(1), and the staffs position on the treatment of safety related and non-safety related SSCs within the scope of license renewal and the SCs requiring an AMR are consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21 (a)(1).On the basis of its review, the staff concludes that the applicant has adequately identified those systems and components that are within the scope of license renewal as required by 10 CFR 54.4(a), and those systems and components that are subject to an AMR as required by 10 CFR 54.21(a)(1). With regard to these matters, the staff concludes that the activities authorized by the renewed license will continue to be conducted in accordance with the CLB, and any changes made to the CLB, to comply with 10 CFR 54.21(a)(1), are in accordance with the NRC's regulations. 2-109 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 offsitepower system long-lived passive SSCs that are part of this circuit path are subject to an AMR will assure that the bases underlying the SBO requirements are maintained over the period of extended license. The applicant includes the complete circuits between the onsite circuits and up to and including the first circuit breakers in the sUbstation (which includes the substation circuit breakers' associated controls and structures) within the scope of license renewal. In Section 2.1.3.4, the applicant states that the boundary between the transmission system and the plant electrical system is the first 230 KV breakers upstream of the 1A and 1 B Auxiliary and Main Transformers. Consequently, the staff concludes that the scoping is consistent with the guidance issued April 1, 2002. This guidance was subsequently incorporated in SRP-LR, Section 2.5.2.1.1. 2.5.1.3 Conclusion The staff reviewed the LRA, the RAI response, and the UFSAR to determine if the applicant failed to identify any SSCs within the s90pe of license renewal. The staff has found no such omissions. In addition, the staff's review determined whether or not the applicant failed to identify any components subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the electrical and I&C systems components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.6 Conclusion

for Scoping and Screening The staff reviewed the information in LRA Section 2, "Scoping and Screening Methodology for Identifying Structures and Components Subject to Aging Management Review, and Implementation Results." The staff finds that the applicant's scoping and screening methodology is consistent with the requirements of 10 CFR 54.21 (a)(1), and the staff's position on the treatment of safety related and non-safety related SSCs within the scope of license renewal and the SCs requiring an AMR are consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1). . On the basis of its review, the staff concludes that the applicant has adequately identified those systems and components that are within the scope of license renewal as required by 10 CFR 54.4(a), and those systems and components that are subject to an AMR as required by 10 CFR 54.21(a)(1). With regard to these matters, the staff concludes that the activities authorized by the renewed license will continue to be conducted in accordance with the CLB, and any changes made to the CLB, to comply with 10 CFR 54.21(a)(1), are in accordance with the NRC's regulations. 2-109

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 Three Mile Island Nuclear Station, Unit 1 (TMI-1), by the staff of the United States Nuclear Regulatory Commission (NRC or the staff).In Appendix B of its license renewal application (LRA), AmerGen Energy Company, LLC (AmerGen or the applicant) described the 38 AMPs it relies on to manage or monitor the aging of passive and long-lived structures and components (SCs).In LRA Section 3, the applicant provided the results of the AMRs for those SCs identified in LRA Section 2 as within the scope of license renewal and subject to an AMR.3.0 Applicant's Use of the Generic Aging Lessons Learned Report In preparing its LRA, the applicant credited NUREG-1801, "Generic Aging Lessons Learned (GALL) Report," Revision 1, dated September 2005. The GALL Report contains the staff's generic evaluation of the existing plant programs and documents the technical basis for determining where existing programs are adequate without modification and where existing programs should be augmented for the period of extended operation. The evaluation results documented in the GALL Report indicate that many of the existing programs are adequate to manage the aging effects for particular SCs for license renewal without change. 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 the programs at its facility correspond to those reviewed and approved in the GALL Report.The purpose of the GALL Report is to provide the staff with 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 used to review an applicant's LRA will be greatly reduced, thereby improving the efficiency and effectiveness of the license renewal review process. The GALL Report also serves as a reference for applicants and staff reviewers to quickly identify those AMPs and activities that the staff has determined will adequately manage or monitor aging during the period of extended operation. The GALL Report identifies: (1) systems, structures, and components (SSCs), (2) SC materials, (3) environments to which the SCs are exposed, (4) the aging effects associated with the materials and environments, (5) the AMPs credited with managing or monitoring the aging effects, and (6) recommendations for further applicant evaluations of aging management for certain component types.The staff performed its review in accordance with the requirements of Title 10, Part 54 of the Code of Federal Regulations (10 CFR Part 54), "Requirements for Renewal of Operating Licenses for Nuclear Power Plants," the guidance provided in NUREG-1 800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plant" (SRP-LR), Revision 1,dated September 2005, and the guidance provided in the GALL Report.In addition to its review of the LRA, the staff conducted an onsite audit of selected AMRs and associated AMPs during the weeks of July 14 and July 28, 2008, respectively, as described in the 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 Three Mile Island Nuclear Station, Unit 1 (TMI-1), by the staff of the United States Nuclear Regulatory Commission (NRC or the staff). In Appendix B of its license renewal application (LRA), AmerGen Energy Company, LLC (AmerGen or the applicant) described the 38 AMPs it relies on to manage or monitor the aging of passive and long-lived structures and components (SCs). In LRA Section 3, the applicant provided the results of the AMRs for those SCs identified in LRA Section 2 as within the scope of license renewal and subject to an AMR. . 3.0 Applicant's Use of the Generic Aging Lessons Learned Report In preparing its LRA, the applicant credited NUREG-1801, "Generic Aging Lessons Learned (GALL) Report," Revision 1, dated September 2005. The GALL Report contains the staff's generic evaluation of the existing plant programs and documents the technical basis for determining where existing programs are adequate without modification and where existing programs should be augmented for the period of extended operation. The evaluation results documented in the GALL Report indicate that many of the existing programs are adequate to manage the aging effects for particular SCs for license renewal without change. 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 the programs at its facility correspond to those reviewed and approved in the GALL Report. The purpose of the GALL Report is to provide the staff with 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 used to review an applicant's LRA will be greatly reduced, thereby improving the efficiency and effectiveness of the license renewal review process. The GALL Report also senies as a reference for applicants and staff reviewers to quickly identify those AMPs and activities that the staff has determined will adequately manage or monitor aging during the period of extended operation. . The GALL Report identifies: (1) systems, structures, and components (SSCs), (2) SC materials, (3) environments to which the SCs are exposed, (4) the aging effects associated with the materials and environments, (5) the AMPs credited with managing or monitoring the aging effects, and (6) recommendations for further applicant evaluations of aging management for certain component types. The staff performed its review in accordance with the requirements of Title 10, Part 54 of the Code of Federal Regulations (10 CFR Part 54), "Requirements for Renewal of Operating Licenses for Nuclear Power Plants," the guidance provided in NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plant" (SRP-LR), Revision 1, dated September 2005, and the guidance provided in the GALL Report. In addition to its review of the LRA, the staff conducted an onsite audit of selected AMRs and associated AMPs during the weeks of July 14 and July 28,2008, respectively, as described in the 3-1 "Audit Report Regarding the Three Mile Island Nuclear Station, Unit-i, License Renewal Application," dated November 24, 2008. The onsite audits and reviews are designed to maximize the efficiency of the staffs LRA review. The applicant can respond to questions, the staff can readily evaluate the applicant's responses, the need for formal correspondence between the staff and the applicant is reduced, and the result is an improvement in review efficiency.

3.0.1 Format

of the License Renewal Application The applicant submitted an application that followed the standard LRA format, as determined by the NRC and the Nuclear Energy Institute (NEI) by letter dated April 7, 2003. This LRA format incorporates lessons learned from the staff's reviews of previous 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 Chapter 3 of the SRP-LR. The AMR results information in LRA Section 3 is presented in the following two table types: (1) Table 3.x.1 -where "3" indicates the LRA section number, "x" indicates the sub-section number from the GALL Report, and "1" indicates that this is the first table type in LRA Section 3.(2) Table 3.x.2-y -where "3" indicates the LRA section number, "x" indicates the sub-section number from the GALL Report, "2" indicates that this is the second table type in LRA Section 3, and "y" indicates the system table number.The content of the previous applications and the TMI-1 application are essentially the same. The intent of the format used for the TMI-1 LRA was to modify the tables in Chapter 3 to provide additional information that would assist the staff in its review. In each Table 1, the applicant summarized the portions of the application that it considered to be consistent with the GALL Report. In each Table 2, the applicant identified the linkage between the scoping and screening results in Chapter 2 and the AMRs in Chapter 3.3.0.1.1 Overview of Table ls Table 3.3.1 (Table 1) provides a summary comparison of how the facility aligns with the corresponding tables of the GALL Report. The table is essentially the same as Tables 1 through 6 provided in the GALL Report, Volume 1, except that the "Type" column has been replaced by an"Item Number" column and the "Related Generic Item" and "Unique Item" columns have been replaced by a "Discussion" column. The "Discussion" column is used by the applicant to provide clarifying and amplifying information. The following are examples of information that might be contained within this column:* further evaluation is documented in subsection x* see subsection x 0 exceptions to the GALL Report assumptions 3-2"Audit Report Regarding the Three Mile Island Nuclear Station, Unit-1, License Renewal Application," dated November 24,2008. The onsite audits and reviews are designed to maximize the efficiency of the staffs LRA review. The applicant can respond to questions, the staff can readily evaluate the applicant's responses, the need for formal correspondence between the staff and the applicant is reduced, and the result is an improvement in review efficiency.

3.0.1 Format

of the License Renewal Application The applicant submitted an application that followed the standard LRA format, as determined by the NRC and the Nuclear Energy Institute (NEI) by letter dated April 7, 2003. This LRA forni1at incorporates lessons learned from the staff's reviews of previous 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 Chapter 3 of the SRP-LR. The AMR results information in LRA Section 3 is presented in the following two table types: (1) Table 3.x.1 -where "3" indicates the LRA section number, "x" indicates the sub-section number from the GALL Report, and "1" indicates that this is the first table type in LRI\ Section 3. (2) Table 3.x.2-y -where "3" indicates the LRA section number, "x" indicates the SUb-section number from the GALL Report, "2" indicates that this is the second table type in LRJi Section 3, and "y" indicates the system table number. The content of the previous applications and the TMI-1 application are essentially the same. The intent of the format used for the TMI-1 LRA was to modify the tables in Chapter 3 to provide additional information that would assist the staff in its review. In each Table 1, the applicant summarized the portions of the application that it considered to be consistent with the GALL I Report. In each Table 2, the applicant identified the linkage between the scoping and screening results in Chapter 2 and the AMRs in Chapter 3. 3.0.1.1 Overview of Table 1s Table 3.3.1 (Table 1) provides a summary comparison of how the facility aligns with the . corresponding tables of the GALL Report. The table is essentially the same as Tables 1 6 provided in the GALL Report, Volume 1, except that the "Type" column has been replaced by an "Item Number" column and the "Related Generic Item" and "Unique Item" columns have been replaced by a "Discussion" column. The "Discussion" column is used by the applicant to pr9vide clarifying and amplifying information. The following are examples of information that might be contained within this column:

  • further evaluation is documented in subsection X
  • see subsection X
  • exceptions to the GALL Report assumptions 3-2
  • discussion of how the line is consistent with the corresponding line item in the GALL Report when this consistency may not be intuitively obvious* discussion of how the item is different from the corresponding line item in the GALL Report (e.g., when there is exception taken to a GALL AMP)The format of Table 1 allows the staff to align a specific Table 1 row with the corresponding GALL Report table row so that the consistency can be checked easily.3.0.1.2 Overview of Table 2s Each Table 3.3.2-y (Table
2) provides the detailed results of the AMRs for those components identified in LRA Section 2 as subject to an AMR. The LRA contains a Table 2 for each of the systems or components within a system grouping (e.g., reactor coolant systems, engineered safety features, auxiliary systems, etc.). For example, the engineered safety features group contains tables specific to the containment spray system, containment isolation system, and emergency core cooling system. Each Table 2 consists of the following nine columns: (1) Component Type -The first column identifies the component types from LRA Section 2 subject to an AMR. The component types are listed in alphabetical order.(2) Intended Function -The second column contains the license renewal intended functions for the listed component types.

Definitions of intended functions are contained in LRA Table 2.1-1.(3) Material -The third column lists the particular materials of construction for the component type.(4) Environment -The fourth column lists the environment to which the component types are exposed. Internal and external service environments are indicated and a list of these.environments is provided in LRA Tables 3.0-1 and 3.0-2.(5) 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. (6) Aging Management Programs -The sixth column lists the AMPs that the applicant used to manage the identified aging effects.(7) GALL Report Volume 2 Line Item -The seventh column lists the GALL Report item(s) that the applicant identified as similar to the AMR results in the LRA. The applicant compared each combination of component type, material, environment, AERM, and AMP in Table 2 of the LRA to the items in the GALL Report. If there were no corresponding items in the GALL Report, the applicant left the column blank. In this way, the applicant identified the AMR results in the LRA tables that corresponded to the items in the GALL Report tables.(8) Table 1 Item -The eighth column lists the corresponding summary item number from Table 1. If the applicant identifies AMR results in Table 2 that are consistent with the GALLReport, then the associated Table 3.x.1 line summary item number should be listed in Table 2. If there is no corresponding item in the GALL Report, then column eight is left blank. That way, the information from the two tables can be correlated. 3-3* discussion of how the line is consistent with the corresponding line item in the GALL Report when this consistency may not be intuitively obvious

  • discussion of how the item is different from the corresponding line item in the GALL Report (e.g., when there is exception taken to a GALL AMP) The format of Table 1 allows the staff to align a specific Table 1 row with the corresponding GALL Report table row so that the consistency can be checked easily. 3.0.1.2 Overview of Table 25 Each Table 3.3.2-y(Table
2) provides the detailed results of the AMRs for those components identified in LRA Section 2 as subject to an AMR. The LRA contains a Table 2 for each of the systems or components within a system grouping (e.g., reactor coolant systems, engineered safety features, auxiliary systems, etc.). For example, the engineered safety features group contains tables specific to the containment spray system, containment isolation system, and emergency core cooling system. Each Table 2 consists of the following nine columns: (1) Component Type -The first column identifies the component types from LRA Section 2 subject to an AMR. The component types are listed in alphabetical order. (2) Intended Function -The second column contains the license renewal intended functions for the listed component types. Definitions of intended functions are contained in LRA Table 2.1-1. (3) Material -The third column lists the particular materials of construction for the component type. (4) Environment -The fourth column lists the environment to which the component types are exposed. Internal and external service environments are indicated and a list of these environments is provided in LRA Tables 3.0-1 and 3.0-2. (5) Aging Effect Requiring Management

-The fifth column lists aging effects requiring management (AERMs). As part of the AMR process, the applicant determined anyAERMs for each combination of material and environment. (6) Aging Management Programs -The sixth column lists the AMPs that the applicant used to manage the identified aging effects. (7) GALL Report Volume 2 Line Item -The seventh column lists the GALL Report item(s) that the applicant identified as similar to the AMR results in the LRA. The applicant compared each combination of component type, material, environment, AERM, and AMP in Table 2 of the LRA to the items in the GALL Report. If there were no corresponding items in the GALL Report, the applicant left the column blank. In this way, the applicant identified the AMR results in the LRA tables that corresponded to the items in the GALL Report tables. (8) Table 1 Item -The eighth column lists the corresponding summary item number from Table 1. If the applicant identifies AMR results in Table 2 that are consistent with the GALL Report, then the associated Table 3.x.1 line summary item number should be listed in Table 2. If there is no corresponding item in the GALL Report, then column eight is left blank. That way, the information from the two tables can be correlated. 3-3 (9) Notes -The ninth column lists the corresponding notes that the applicant used to identify how the information in Table 2 aligns with the information in the GALL Report. The notesidentified by letters were developed by an NEI working group and will be used in future LRAs. Any plant-specific notes are identified by a number and provide additional information concerning the consistency of the line item with the GALL Report.3.0.2 Staff's Review Process The staff conducted the following three types of evaluations of the AMRs and associated AMPs: (1) For items that the applicant stated were consistent with the GALL Report, the staff conducted either an audit or a technical review to determine consistency. (2) For items that the applicant stated were consistent with the GALL Report with exceptions and/or enhancements, the staff conducted either an audit or a technical review of the item to determine consistency with the GALL Report. In addition, the staff conducted either an audit or a technical review of the applicant's technical justification for the exceptions' and the adequacy of the enhancements. (3) For other items, the staff conducted a technical review pursuant to 10 CFR 54.21(a)(3). These audits and technical reviews determine whether the effects of aging on SCs can be adequately managed so that the intended functions can be maintained consistent with the plant's current licensing basis (CLB) for the period of extended operation, as required by 10 CFR Part 54.3.0.2.1 Review of AMPs For those AMPs for which the applicant had claimed consistency with the GALL Report AMIPs, the staff conducted either an audit or a technical review to confirm that the applicant's AMPs were consistent with the GALL Report. For each AMP that had one or more deviations, the staff evaluated each deviation to determine whether the deviation was acceptable and whether the AMP, as modified, would adequately manage the aging effect(s) for which it was credited. For AMPs that were not addressed in the GALL Report, the staff performed a full review to determine their adequacy. The staff evaluated the AMPs against the following 10 program elements defined in SRP-LR Appendix A.(1) Scope of Program: The scope of 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). 11 (4) Detection of Aging Effects: Detection of aging effects including such aspects as method or technique (i.e., visual, volumetric, surface inspection), frequency, sample size, dataýcollection, and timing of new/one-time inspections should occur before there is a loss of structure or component intended function(s). 3-4 (9) Notes -The ninth column lists the corresponding notes that the applicant used to identify how the information in Table 2 aligns with the information in the GALL Report. The notes identified by letters were developed by an NEI working group and will be used in future LRAs. Any plant-specific notes are identified by a number and provide additional information concerning the consistency of the line item with the GALL Report. 3.0.2 Staff's Review Process The staff conducted the following three types of evaluations of the AMRs and associated AfY1Ps: (1) For items that the applicant stated were consistent with the GALL Report, the staff conducted either an audit or a technical review to determine consistency. (2) For items that the applicant stated were consistent with the GALL Report with exceptions and/or enhancements, the staff conducted either an audit or a technical review of the item to determine consistency with the GALL Report. In addition, the staff conducted an audit or a technical review of the applicant's technical justification for the exceptions' and the adequacy of the enhancements. (3) For other items, the staff conducted a technical review pursuant to 10 CFR 54.21(a)(3). These audits and technical reviews determine whether the effects of aging on SCs can be : adequately managed so that the intended functions can be maintained consistent with the plant's current licensing basis (CLS) for the period of extended operation, as required by 10 CFR Part 54. 3.0.2.1 Review of AMPs For those AMPs for which the applicant had claimed consistency with the GALL Report AMPs, the staff conducted either an audit or a technical review to confirm that the applicant's AMPs consistent with the GALL Report. For each AMP that had one or more deviations, the staff:: evaluated each deviation to determine whether the deviation was acceptable and whether the AMP, as modified, would adequately manage the aging effect(s) for which it was credited. for AMPs that were not addressed in the GALL Report, the staff performed a full review to determine their adequacy. The staff evaluated the AMPs against the following 10 program elements defined in SRP-LR Appendix A. (1) Scope of Program: The scope of program should include the specific SCs' subject to an AMR for license renewal. (2) (3) (4) Preventive Actions: Preventive actions should prevent or mitigate aging degradation. Parameters Monitored or Inspected: Parameters monitored or inspected should be linked to the degradation of the particular structure or component intended function(s).

' Detection of Aging Effects: Detection of aging effects including such aspects as method or technique (Le., visual, volumetric, surface inspection), frequency, sample size, data collection, and timing of new/one-time inspections should occur before there is a loss of structure or component intended function( s). 3-4 (5) Monitoring and Trending:

Monitoring and trending should provide predictability of the extent of degradation, as well as timely corrective or mitigative actions.(6) Acceptance Criteria: Acceptance criteria, against which the need for corrective action will be evaluated, should ensure that the structure or component intended function(s) are maintained under all CLB design conditions during the period of extended operation. (7) Corrective Actions: Corrective actions, including root cause determination and prevention of recurrence, should be timely.(8) Confirmation Process: Confirmation process should ensure that preventive actions are adequate and that appropriate and effective corrective actions have been completed. (9) Administrative Controls: Administrative controls should provide 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 managed adequately 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) and (10) are documented in the Aging Management Program Audit Report and summarized in SER Section 3.0.3.The staff reviewed the applicant's corrective action program and documented its evaluations in SER Section 3.0.4. The staff's evaluation of the corrective actions program included assessment of the following program elements: (7) "corrective actions," (8) "confirmation process," and (9)"administrative controls." The staff reviewed the updated final safety analysis report (UFSAR) supplement for each AMP to determine if it provided an adequate description of the program or activity, as required by 10 CFR 54.21(d).3.0.2.2 Review of AMR Results Table 2 contains information concerning whether the AMRs align with the AMRs identified in the GALL Report. For a given AMR in Table 2, the staff reviewed the intended function, material, environment, AERM, and AMP combination for a particular component type within a system. The AMRs that correlate between a combination in Table 2 and a combination in the GALL Report were identified by a referenced item number in column seven, "NUREG-1801 Volume 2 Line Item." The staff also conducted onsite audits to verify the correlation. A blank column seven indicates that the applicant was unable to locate an appropriate corresponding combination in the GALL Report. The staff conducted a technical review of these combinations not consistent with the GALL Report. The next column, "Table 1 Item," provides a reference number that indicatesthe corresponding row in Table 1.3-5 (5) Monitoring and Trending: Monitoring and trending should provide predictability of the extent of degradation, as well as timely corrective or mitigative actions. (6) Acceptance Criteria: Acceptance criteria, against which the need for corrective action will be evaluated, should ensure that the structure or component intended function(s) are maintained under all CLB design conditions during the period of extended operation. (7) Corrective Actions: Corrective actions, including root cause determination and prevention of recurrence, should be timely. (8) Confirmation Process: Confirmation process should ensure that preventive actions are adequate and that appropriate and effective corrective actions have been completed. (9) Administrative Controls: Administrative controls should provide 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 managed adequately 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) and (10) are documented in the Aging Management Program Audit Report and summarized in SER Section 3.0.3. The staff reviewed the applicant's corrective action program and documented its evaluations in SER Section 3.0.4. The staff's evaluation of the corrective actions program included assessment of the following program elements: (7) "corrective actions," (8) "confirmation process," and (9) "administrative controls." The staff reviewed the updated final safety analysis report (UFSAR) supplement for each AMP to determine if it provided an adequate description of the program or activity, as required by 10 CFR 54.21(d). 3.0.2.2 Review of AMR Res,ults Table 2 contains information concerning whether the AMRs align with the AMRs identified in the GALL Report. For a given AMR in Table 2, the staff reviewed the intended function, material, environment, AERM, and AMP combination for a particular component type within a system. The AMRs that correlate between a combination in Table 2 and a combination in the GALL Report were identified by a referenced item number in column seven, "NUREG-1801 Volume 2 Line Item." The staff also conducted onsite audits to verify the correlation. A blank column seven indicates that the applicant was unable to locate an appropriate corresponding combination in the GALL Report. The staff conducted a technical review of these combinations not consistent with the GALL Report. The next column, "Table 1 Item," provides a reference number that indicates the corresponding row in Table 1. 3-5 3.0.2.3 UFSAR Supplement Consistent with the SRP-LR, for the AMRs and associated AMPs that it reviewed, the staff also reviewed the UFSAR Supplement that summarizes the applicant's programs and activities for managing the effects of aging for the period of extended operation, as required by 10 CFR 54.21(d). 3.0.2.4 Documentation and Documents Reviewed In performing its review, the staff used the LRA, LRA supplements, SRP-LR, and GALL Report.Also, during the onsite audit, the staff examined the applicant's justifications, as documented in the Audit Summary Report, to verify that the applicant's activities and programs will adequately manage the effects of aging on SOs. The staff also conducted detailed discussions and interviews with the applicant's license renewal project personnel and others with technical expertise relevant to aging management.

3.0.3 Aging

Management Programs SER Table 3.0.3 -1 below presents the AMPs credited by the applicant and described in LRA Appendix B. The table also indicates the GALL Report AMP that the applicant claimed its AMP was consistent with, if applicable, and the SSCs for managing or monitoring aging. The section of the SER, in which the staff's evaluation of the program is documented, is also provided.Table 3.0.3 -I TMI-1 Aging Management Programs ApplicantAiO L RA' *NeiWbr Appliclant ALRpdr-gn; SER:, Management Sections Existing .comparison to. Manage4ment Sec tion Program,_'... Program the ýGALL: Programs ASME Section Xl A.2.1.1 Existing Consistent with XI.M1, "ASME 3.0.3.2.1 Inservice Inspection, B.2.1.1 Exceptions Section XI Inservice., Subsections IWB, Inspection, IWC, and IWD Subsections IWB, Program IWC, and IWD" _ _Water Chemistry A.2.1.2 Existing Consistent with XI.M2, 'Water 3.0.3.2.2 B.2.1.2 Enhancement Chemistry" Reactor Head Closure A.2.1.3 Existing Consistent with XI.M3, "Reactor Head 3.0.3.2.3 Studs B.2.1.3 Exceptions Closure Studs" Boric Acid Corrosion A.2.1.4 Existing. Consistent XI.M10, "Boric Acid 3.0.3.1.1 Program B.2.1.4 Corrosion ,_Nickel-Alloy A.2.1.5 Existing Consistent XI.M11A, "Nickel- 3.0.3.1.2 Penetration Nozzles B.2.1.5 Alloy Penetration Welded to the Upper Nozzles Welded to Reactor Vessel the Upper Reactor Closure Heads of Vessel Closure Heads Pressurized Water of Pressurized Water Reactors Reactors" Flow Accelerated A.2.1.6 Existing Consistent with XI.M17, "Flow 3.0.3.2.4 Corrosion Program B.2.1.6 Exception Accelerated Corrosion" 3-6 3.0.2.3 UFSAR Supplement Consistent with the SRP-LR, for the AMRs and associated AMPs that it reviewed, the staff also reviewed the UFSAR Supplement that summarizes the applicant's programs and activities for* managing the effects of aging for the period of extended operation, as required by 10 CFR 54.21(d). 3.0.2.4 Documentation and Documents Reviewed In performing its review, the staff used the LRA, LRA supplements, SRP-LR, and GALL Report. Also, during the onsite audit, the staff examined the applicant's J'ustifications, as documented in I' the Audit Summary Report, to verify that the applicant's activities and programs will adequately manage the effects of aging on SCs. The staff also conducted detailed discussions and interviews with the applicant's license renewal project personnel and others with technical expertise relevant to aging management. .. 3.0.3 Aging Management Programs SER Table 3.0.3 -1 below presents the AMPs credited by the applicant and described in LRA Appendix B. The table also indicates the GALL Report AMP that the applicant claimed its AMP was consistent with, if applicable, and the SSCs for managing or monitoring aging. The of the SER, in which the staff's evaluation of the program is documented, is also provided. ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program Water Chemistry Reactor Head Closure Studs Boric Acid Corrosion Program Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Flow Accelerated Corrosion Program Table 3.0.3 -1 TMI*1 Aging Management Programs A.2.1.1 B.2.1.1 A.2.1.2 B.2.1.2 A.2.1.3 B.2.1.3 A.2.1.4 8.2.1.4 A.2.1.5 B.2.1.5 A.2.1.6 B.2.1.6 Existing Existing Existing Existing. Existing Existing 3-6 Consistent with Exceptions Consistent with Enhancement Consistent with Exceptions Consistent Consistent Consistent with Exception XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 3.0.3.2.1 XI.M2, 'Water 3.0.3.2.2 Chemistry" XI.M3, "Reactor Head 3.0.3.2.3 Closure Studs" XI.M10, "Boric Acid 3.0.3.1.1 Corrosion XI.M11 A, "Nickel-3.0.3.1.2 Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors" XI.M17, "Flow Accelerated Corrosion" 3.0.3.2.4 policant Aging L,'LRA New or. Appl llAiiCanit' GALL Report Agingri' SER-_Management Sections, Existing Comparison to Management ,Sectionr Program Program. the~i GALL Programs..Bolting Integrity A.2.1.7 Existing Consistent XI.M18, "Bolting 3.0.3.1.3 Program B.2.1.7 Integrity" Steam Generator Tube A.2.1.8 Existing Consistent XI.M19, "Steam 3.0.3.1.4 Integrity Program B.2.1.8 Generator Tube Integrity" Open Cycle Cooling A.2.1.9 Existing Consistent with XI.M20, "Open-Cycle 3.0.3.2.5 Water Program B.2.1.9 Exception and Cooling WaterEnhancement System" Closed Cycle Cooling A.2.1.10 Existing Consistent with XI.M21, "Closed 3.0.3.2.6 Water Program B.2.1.10 Exception and Cycle Cooling Water Enhancement System" Inspection of A.2.1.11 Existing Consistent with XI.M23, "Inspection of 3.0.3.2.7 Overhead Heavy Load B.2.1.11 Enhancements Overhead Heavy and Light Load Load and Light Load (Related to Refueling) (Related to Refueling) Handling Systems Handling Systems" Compressed Air A.2.1.12 Existing Consistent with XI.M24, "Compressed 3.0.3.2.8 Monitoring Program B.2.1.12 Enhancements Air Monitoring" Fire Protection A.2.1.13 Existing Consistent with XI.M26, "Fire 3.0.3.2.9 Program B.2.1.13 Exception and Protection" Enhancements Fire Water System A.2.1.14 Existing Consistent with XI.M27, "Fire Water 3.0.3.2.10 B.2.1.14 Enhancements System" Aboveground Steel A.2.1.15 Existing Consistent with XI.M29, 3.0.3.2.11 Tanks B.2.1.15 Exception and "Aboveground Steel Enhancements Tanks" Fuel Oil Chemistry A.2.1.16 Existing Consistent with XI.M30, "Fuel Oil 3.0.3.2.12 B.2.1.16 Exceptions and Chemistry" EnhancementsReactor Vessel A.2.1.17 Existing Consistent with XI.M31, "Reactor 3.0.3.2.13 Surveillance B.2.1.17 enhancements Vessel Surveillance" One-Time Inspection A.2.1.18 New Consistent with XI.M32, "One-Time 3.0.3.2.14 Program B.2.1.18 Exception Inspection" Selective Leaching of A.2.1.19 New Consistent XI.M33, "Selective 3.0.3.1.5 Materials B.2.1.19 Leaching of Materials" Buried Piping and A.2.1.20 Existing Consistent with XI.M34, "Buried 3.0.3.2.15 Tanks Inspection B.2.1.20 Exceptions and Piping and Tanks Enhancements Inspection" External Surfaces A.2.1.21 New Consistent with XI.M36, "External 3.0.3.2.16 Monitoring B.2.1.21 Exception Surfaces Monitoring" Inspection of Internal A.2.1.22 New Consistent with XI.M38, "Inspection of 3.0.3.2.17 Surfaces in B.2.1.22 Exceptions Internal Surfaces in Miscellaneous Piping Miscellaneous Piping and Ducting and Ducting Components Components" 3-7 Bolting Integrity A.2.1.7 Existing Consistent XI.M18, "Bolting 3.0.3.1.3 Program B.2.1.7 Integrity" Steam Generator Tube Integrity Program Open Cycle Cooling Water Program Closed Cycle Cooling Water Program Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Compressed Air Monitoring Program Fire Protection Program Fire Water System Aboveground Steel Tanks Fuel Oil Chemistry Reactor Vessel Surveillance One-Time Inspection Program Selective Leaching of Materials Buried Piping and Tanks Inspection External Surfaces Monitoring Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components A.2.1.8 B.2.1.8 A.2.1.9 B.2.1.9 A.2.1.10 B.2.1.10 A.2.1.11 B.2.1.11 A.2.1.12 B.2.1.12 A.2.1.13 B.2.1.13 A.2.1.14 B.2.1.14 A.2.1.15 B.2.1.15 A.2.1.16 B.2.1.16 A.2.1.17 B.2.1.17 A.2.1.18 B.2.1.18 A.2.1.19 B.2.1.19 A.2.1.20 B.2.1.20 A.2.1.21 B.2.1.21 A.2.1.22 B.2.1.22 Existing Existing Existing Existing Existing Existing Existing Existing Existing Existing New New Existing New New 3-7 Consistent Consistent with Exception and Enhancement Consistent with Exception and Enhancement Consistent with Enhancements Consistent with Enhancements Consistent with Exception and Enhancements Consistent with Enhancements Consistent with Exception and Enhancements Consistent with Exceptions and Enhancements Consistent with enhancements Consistent with Exception Consistent Consistent with Exceptions and Enhancements Consistent with Exception Consistent with Exceptions XI.M19, "Steam Generator Tube Integrity" XI.M20, "Open-Cycle Cooling Water System" XI. M21, "Closed Cycle Cooling Water System" 3.0.3.1.4 3.0.3.2.5 3.0.3.2.6 XI.M23, "Inspection of 3.0.3.2.7 Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems" XI.M24, "Compressed 3.0.3.2.8 Air Monitoring" XI.M26, "Fire Protection" XI.M27, "Fire Water System" XI.M29, "Aboveground Steel Tanks" XI.M30, "Fuel Oil Chemistry" 3.0.3.2.9 3.0.3.2.10 3.0.3.2.11 3.0.3.2.12 XI.M31, "Reactor 3.0.3.2.13 Vessel Surveillance" XI.M32, "One-Time 3.0.3.2.14 Inspection" XI.M33, "Selective 3.0.3.1.5 Leaching of Materials" XI.M34, "Buried 3.0.3.2.15 Piping and Tanks Inspection" XI.M36, "External 3.0.3.2.16 Surfaces Monitoring" XI.M38, "Inspection of 3.0.3.2.17 Internal Surfaces in Miscellaneous Piping and Ducting Components" ApplicantAgingmLRAew.or Applicant'- GALLt eR Management Sections Existing.. Comparison to Management Section Program Program the GALL Programs-, Report!Lubricating Oil A.2.1.23 Existing Consistent with XI.M39, "Lubricating 3.0.3.2.18 Analysis B.2.1.23 Exception Oil Analysis" ASME Section Xl, A.2.1.24 Existing Consistent with XI.S1, "ASME Section 3.0.3.2.19 Subsection IWE B.2.1.24 Exception Xl, Subsection IWE" ASME Section Xl, A.2.1.25 Existing Consistent XI.S2, "ASME Section 3.0.3.1.6 Subsection IWL B.2.1.25 Xl, Subsection IWL" ASME Section Xl, A.2.1.26 Existing Consistent with XI.S3, "ASME Section 3.0.3.2.20 Subsection IWF B.2.1.26 Exception Xl, Subsection IWF" 10 CFR 50, Appendix A.2.1.27 Existing Consistent XI.S4, "10 CFR 50 3.0.3'.1.7 J B.2.1.27 Appendix J" X Structures Monitoring A.2.1.28 Existing Consistent with XI.S6, "Structures 3.0.3.2.21 Program B.2.1.28 Enhancements Monitoring Program" Protective Coating A.2.1.29 Existing Consistent XI.S8, "Protective 3.0.3.1.8 Monitoring and B.2.1.29 Coating Monitoring Maintenance Program and Maintenance Program" Electrical Cables and A.2.1.30 New Consistent XI.E1, "Electrical 3.0.3.1.9 Connections Not B.2.1.30 Cables and Subject to 10 CFR Connections Not 50.49 Environmental Subject to 10 CFR Qualification 50.49 Requirements Environmental Qualification Requirements" Electrical Cables and A.2.1.31 Existing Consistent with XI.E2, "Electrical 3.0.3.2.22 Connections Not B.2.1.31 Enhancement Cables and Subject to 10 CFR Connections Not 50.49 Environmental Subject to 10 CFR Qualification 50.49 Requirements Used in Environmental Instrumentation Qualification Circuits Requirements Used in Instrumentation Circuits" Inaccessible Medium A.2.1.32 New Consistent Xl.E3, "Inaccessible 3.0.3.1.10 Voltage Cables Not B.2.1.32 Medium-Voltage Subject to 10 CFR Cables Not Subject to 50.49 Environmental 10 CFR 50.49 Qualification Environmental Requirements Qualification Requirements" Metal Enclosed Bus A.2.1.33 Existing Consistent with XI.E4, "Metal 3.0.3.2.23 B.2.1.33 Enhancement Enclosed Bus" 3-8 Lubricating Oil Analysis ASME Section XI, Subsection IWE ASME Section XI, Subsection IWL ASME Section XI, Subsection IWF 10 CFR 50, Appendix J Structures Monitoring Program Protective Coating Monitoring and Maintenance Program Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Electrical Cables and Connections Not Subjectto 10 CFR 50.49 Environmental . Qualification Requirements Used in Instrumentation Circuits Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Metal Enclosed Bus A.2.1.23 B.2.1.23 A.2.1.24 B.2.1.24 A.2.1.25 B.2.1.25 A.2.1.26 B.2.1.26 A.2.1.27 B.2.1.27 A.2.1.28 B.2.1.28 A.2.1.29 B.2.1.29 A.2.1.30 B.2.1.30 A.2.1.31 B.2.1.31 A.2.1.32 B.2.1.32 A.2.1.33 B.2.1.33 Existing Existing Existing Existing Existing Existing Existing New Existing New Existing 3-8 Consistent with Exception Consistent with Exception Consistent Consistent with Exception Consistent Consistent with Enhancements Consistent Consistent Consistent with Enhancement Consistent Consistent with Enhancement XLM39, "Lubricating 3.0.3.2.18 Oil Analysis" XLS1, "ASME Section 3.0.3.2.19 XI, Subsection IWE" XLS2, "ASME Section 3.0.3.1.6 XI, Subsection IWL" XLS3, "ASME Section 3.0.3.2.20 XI, Subsection IWF" XLS4, "10 CFR 50 3.0j.1.7 Appendix J" XLS6, "Structures 3.0.3.2.21 Monitoring Program" XLS8, "Protective 3.0.3.1.8 Coating Monitoring and Maintenance Program" XLE1, "Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements" 3.0.3.1.9 XLE2, "Electrical 3.0.3.2.22 Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits" " XLE3, "Inaccessible 3.0.3.1.10 Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements" XLE4, "Metal 3.0.3.2.23 Enclosed Bus" ElApplicant A GALL R6,EectAging 3 ER Mhnagement .Sedtidns Existing. C prsn...Mna gement eto Program .Program thdALPrograms, Rport'.Electrical Cable A.2.1 .34 New Consistent with XI.E6, "Electrical 3.0.3.2.24 Connections Not B.2.1.34 Exceptions Cable Connections Subject to 10 CFR Not Subject to 10 50.49 Environmental CFR 50.49 Qualification Environmental Requirements Qualification Requirements" Nickel Alloy Aging A.2.2.1 Existing Plant Specific XI.M11A, "Nickel Alloy 3.0.3.3.1 Management Program B.2.2.1 Aging Management Program" Metal Fatigue of A.3.1.1 Existing Consistent with X.M1, "Metal Fatigue 3.0.3.2.25 Reactor Coolant B.3.1.1 Enhancement of Reactor Coolant Pressure Boundary Pressure Boundary" Concrete Containment A.3.1.2 Existing Consistent with X.S1, "Concrete 3.0.3.2.26 Tendon Prestress B.3.1.2 Exception Containment Tendon Prestress" Environmental A.3.1.3 Existing Consistent X.E1, "Environmental 3.0.3.1.11 Qualification (EQ) of B.3.1.3 Qualification (EQ) of Electrical Components _ II_ IElectric Components" 3.0.3.1 AMPs That Are Consistent with the GALL Report In LRA Appendix B, the applicant identified the following AMPs Report: as being consistent with the GALL* Boric Acid Corrosion* Nickel Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads ofPressurized Water Reactors* Bolting Integrity* Steam Generator Tube Integrity* Selective Leaching of Materials 0 ASME Section XI, Subsection IWL* 10 CFR Part 50, Appendix J* Protective Coating Monitoring and Maintenance Program* Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements 0 Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements 0 Environmental Qualification of Electric Components 3-9 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Nickel Alloy Aging Management Program Metal Fatigue of Reactor Coolant Pressure Boundary Concrete Containment Tendon Prestress Environmental Qualification (EQ) of Electrical Components A.2.1.34 B.2.1.34 A.2.2.1 B.2.2.1 A.3.1.1 B.3.1.1 A.3.1.2 B.3.1.2 A.3.1.3 B.3.1.3 New Existing Existing Existing Existing Consistent with Exceptions Plant Specific Consistent with Enhancement Consistent with Exception Consistent 3.0.3.1 AMPs That Are Consistent with the GALL Report XI.E6, "Electrical Cable Connections Not Subjectto 10 CFR 50.49 Environmental Qualification Requirements" 3.0.3.2.24 XI.M11A, "Nickel Alloy 3.0.3.3.1 Aging Management Program" X.M1, "Metal Fatigue 3.0.3.2.25 of Reactor Coolant Pressure Boundary" X.S1, "Concrete 3.0.3.2.26 Containment Tendon Prestress" X.E1, "Environmental 3.0.3.1.11 Qualification (EQ) of Electric Components" In LRA Appendix B, the applicant identified the following AMPs as being consistent with the GALL Report:

  • Boric Acid Corrosion
  • Nickel Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors
  • Bolting Integrity
  • Steam Generator Tube Integrity
  • Selective Leaching of Materials
  • ASME Section XI, Subsection IWL
  • 10 CFR Part 50, Appendix J
  • Protective Coating Monitoring and Maintenance Program
  • Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements
  • Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements
  • Environmental Qualification of Electric Components 3-9 3.0.3.1.1 Boric Acid Corrosion Summary of Technical Information in the Application.

LRA Section B.2.1.4 describes the existing Boric Acid Corrosion Program as being consistent with GALL AMP XI.M1 0, "Boric Acid Corrosion." The applicant stated that the program includes provisions to identify, inspect, examine and evaluate leakage, and initiate corrective action, and relies in part on implementation of recommendations of NRC Generic Letter 88-05, "Boric Acid Corrosion of Carbon Steel Reactor Components in PWR plants" and also includes visual examinations of Alloy 600 components for stress corrosion cracking due to boric acid leakage.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report.The staff reviewed the applicant's license renewal basis document and determined that the program scope includes the systems and components that could be affected by boric acid corrosion. In comparing the program elements in the applicant's program to those in the GALL AMP XI.M10, the staff determined that the applicant's program elements are consistent with the recommendations of GALL AMP XI.M10, but also identified an issue with the "scope of program" program element for which the staff requested additional information. The staff could not determine whether all the components, including all Class 1 nickel alloy locations as per NRC Order EA-03-009, Bulletins 2003-02 and 2004-01, were included in the"scope of the program" element for visual inspection. In RAI B.2.1.4-1, dated September 29, 2008, the staff requested that the applicant provide the following information: (a) Clarification as to which components are included within the scope of the AMP, and, whether the scope includes all Class 1 nickel alloy locations (b) For in-scope nickel alloy locations (if any), clarification of whether or not the examinations will be implemented through this AMP or another AMP discussed in the LRA. If another AMP will be used for specific components, clarification as to which AMP will be implemented for the examination(c) Clarification as to which programs will be used to evaluate the evidence of leakage that is detected through the AMP or other AMPs (d) For the in-scope nickel-alloy components, clarification of what type of visual examinations (i.e., specify whether VT-1, VT-2 or VT-3, and whether the visual examinations are enhanced, bare-surface, qualified, etc.) will be performed on the components In its response dated October 20, 2008, the applicant stated that components and structures included in the scope of the Boric Acid Corrosion Program include all components from which borated water can leak and all structures and components within the vicinity of potential borated water leakage, which includes all components within the Reactor, Auxiliary, and Fuel Handling 3-10 3.0.3.1.1 Boric Acid Corrosion Summary of Technical Information in the Application. LRA Section B.2.1.4 describes the ex!sting Boric Acid Corrosion Program as being consistent with GALL AMP XI.M1 0, "Boric Acid Corrosion." The applicant stated that the program includes provisions to identify, inspect, examine and evaluate leakage, and initiate corrective action, and relies in part on implementation of recommendations of NRC Generic Letter 88-05, "Boric Acid Corrosion of Carbon Steel Reactor Components in PWR plants" and also includes visual examinations of Alloy 600 components for stress corrosion cracking due to boric acid leakage. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the applicant's license renewal basis document and determined that the program scope includes the systems and components that could be affected by boric acid corrosion. In comparing the program elements in the applicant's program to those in the GALL AMP XI.M1 0, the staff determined that the applicant's program elements are consistent with the .* recommendations of GALL AMP XI.M10, but also identified an issue with the "scope of program" program element for which the staff requested additional information. h The staff could not determine whether all the components, including all Class 1 nickel alloy locations as per NRC Order EA-03-009, Bulletins 2003-02 and 2004-01, were included in the "scope of the program" element for visual inspection. In RAI B.2.1.4-1, dated September 29, 2008, the staff requested that the applicant provide the following information: (a) Clarification as to which components are included within the scope of the AMP, and , whether the scope includes all Class 1 nickel alloy locations . (b) For in-scope nickel alloy locations (if any), clarification of whether or not the examinations will be implemented through this AMP or another AMP discussed in the LRA. If another AMP will be used for specific components, clarification as to which AMP will be implemented for the examination (c) Clarification as to which programs will be used to evaluate the evidence of leakage that is detected through the AMP or other AMPs (d) For the in-scope nickel-alloy components, clarification of what type of visual (Le., specify whether VT-1, VT-2 or VT-3, and whether the visual examinations are :, enhanced, bare-surface, qualified, etc.) will be performed on the components In its response dated October 20, 2008, the applicant stated that components and structures included in the scope of the Boric Acid Corrosion Program include all components from which borated water can leak and all structures and components within the vicinity of potential borated water leakage, which includes all components within the Reactor, Auxiliary, and Fuel Handling 3-10 Buildings. The applicant also stated that Class 1 nickel alloy components located in these buildings are included in the scope of the program.The applicant further stated that for in-scope nickel alloy locations, visual inspections are performed under the "Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors" program, (B.2.1.5), or the "Nickel Alloy Aging Management Program," (B.2.2.1) by using UT-2 qualified personnel. The applicant also stated that both these programs and the Boric Acid Corrosion Program direct inspections, however, evaluations of borated water leakage, regardless of which program detected the leak, are performed under the Boric Acid Corrosion program. The applicant also stated that the visual examinations are consistent with the requirements of 10 CFR 50.55a and recommendations of Code Cases N-722 and 729-1.Based on its review, the staff finds the applicant's response to RAI B.2.1.4-1 acceptable because the applicant clarified the scope of the program, indicated which program performs the visual examinations for the nickel alloy components, and confirmed that evaluations of any boratedwater leakage is performed under the Boric Acid Corrosion Program. The staff's concern described in RAI B.2.1.4-1 is resolved.The staff confirmed that in the LRA, the applicant's AMR line item results for applicable Table 2 items credits the Boric Acid Corrosion Program to manage loss of material due to boric acid corrosion in steel, copper alloy, and aluminum alloy component surfaces and concrete structures that may be potentially exposed to leakage from borated water systems.Based on its review, the staff finds the applicant's Boric Acid Corrosion Program consistent with the program elements of GALL AMP XI.M10, "Boric Acid Corrosion Program," and acceptable. Operatinq Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.4 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The staff reviewed the "operating experience" discussion in the applicant's license renewal basis document for the Boric Acid Corrosion Program and also a sample of condition reports and confirmed that the applicant identified boric acid corrosion and implemented appropriate corrective actions.The "operating experience" program element for LRA Section B.2.1.4 states that in November 2006 an active borated water leak was identified dripping from a reactor coolant valve threaded fitting. The applicant stated that corrective actions were initiated by having the fitting repaired and the area cleaned and that no degradation was identified at the time. The applicant also stated that the fitting was subsequently inspected and no leakage was identified. The applicant also stated that wet boron buildup was discovered in November 2006 on a differential pressure transmitter and other components within the immediate vicinity and that the general area where the boric acid leak was occurring was inspected and no corrosion was observed. The applicant stated that the leak from the relief valve was repaired and the general areas cleaned. The applicant also stated that periodic self-assessments of the Boric Acid Corrosion Program are performed to identify the areas that need improvement to maintain the quality of the program.3-11 Buildings. The applicant also stated that Class 1 nickel alloy components located in these buildings are included in the scope of the program. The applicant further stated that for in-scope nickel alloy locations, visual inspections are performed under the "Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors" program, (B.2.1.5), or the "Nickel Alloy Aging Management Program," (B.2.2.1) by using UT-2 qualified personnel. The applicant also stated that both these programs and the Boric Acid Corrosion Program direct inspections, however, evaluations of borated water leakage, regardless of which program detected the leak, are performed under the Boric Acid Corrosion program. The applicant also stated that the visual examinations are consistent with the requirements of 10 CFR 50.55a and recommendations of Code Cases N-722 and 729-1. Based on its review, the staff finds the applicant's response to RAI B.2.1.4-1 acceptable because the applicant clarified the scope of the program, indicated which program performs the visual examinations for the nickel alloy components, and confirmed that evaluations of any borated water leakage is performed under the Boric Acid Corrosion Program. The staff's concern described in RAI B.2.1.4-1 is resolved. The staff confirmed that in the LRA, the applicant's AMR line item results for applicable Table 2 items credits the Boric Acid Corrosion Program to manage loss of material due to boric acid corrosion in steel, copper alloy, and aluminum alloy component surfaces and concrete structures that may be potentially exposed to leakage from borated water systems. Based on its review, the staff finds the applicant's Boric Acid Corrosion Program consistent with the program elements of GALL AMP XI.M10, "Boric Acid Corrosion Program," and acceptable. Operating Experience. The staff reviewed the operating experience provided in LRA SeCtion B.2.1.4 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The staff reviewed the "operating experience" discussion in the applicant's license renewal basis document for the Boric Acid Corrosion Program and also a sample of condition reports and confirmed that the applicant identified boric acid corrosion and implemented appropriate corrective actions. The "operating experience" program element for LRA Section B.2.1.4 states that in November 2006 an active borated water leak was identified dripping from a reactor coolant valve threaded fitting. The applicant stated that corrective actions were initiated by having the fitting repaired and the area cleaned and that no degradation was identified at the time. The applicant also stated that the fitting was subsequently inspected and no leakage was identified. The applicant also stated that wet boron buildup was discovered in November 2006 on a differential pressure transmitter and other components within the immediate vicinity and that the general area where the boric acid leak was occurring was inspected and no corrosion was observed. The applicant stated that the leak from the relief valve was repaired and the general areas cleaned. The applicant also stated that periodic self-assessments of the Boric Acid Corrosion Program are performed to identify the areas that need improvement to maintain the quality of the program. 3-11 Based on its review, the staff finds that the applicant has demonstrated that its Boric AcidCorrosion Program is capable of identifying, monitoring, and correcting the effects of boric acid corrosion on the intended function of components that may be exposed to borated water leakage, because the staff has confirmed that the program is consistent with the recommendations in GALL AMP XI.M10 and the program is updated to account for relevant operating experience. The staff finds that the Boric Acid Corrosion Program can be expected to ensure that the systers and components within the scope of the program will continue to perform their intended functions consistent with the CLB for 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. LRA Section A.2.1.4, provides the applicant's UFSAR Supplement for the Boric Acid Corrosion Program. The staff confirmed that the applicant's UFSAR Supplement , summary description for this program conforms to the staffs recommended UFSAR Supplelment guidance found in SRP LR Table 3.1-2.In LRA Section A.5, Commitment No. 4, the applicant committed to implement the Boric Acid Corrosion Program on an on-going basis during the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Boric Acid Corrosion Program as required by 10 CFR 54.21(d).Conclusion. On the basis of its audit and review of the applicant's Boric Acid Corrosion Program and the applicant's response to the RAI, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d).3.0.3.1.2 Nickel Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Summary of Technical Information in the Application. LRA Section B.2.1.5 describes the existing Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of ýýPressurized Water Reactors Program as being consistent to GALL AMP XI.M1 1A, "Nickel-,Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors." The applicant stated that this program has been established to ensure that augmented inservice inspections (ISI) of all nickel alloy vessel head penetration (VHP) nozzles welded to the upper reactor vessel (RV) head will continue to be performed as mandated by the interim requirements of NRC Order EA-03-009, "Issuance of Order Establishing Interim Inspection Requirements for Reactor Pressure Vessel Heads at Pressurized Water Reactors (PWRs)," as amended by the First Revision of the Order, or by any subsequent NRC requirements that may be established to supersede the requirements of the Order.3-12 Based on its review, the staff finds that the applicant has demonstrated that its Boric Acid, Corrosion Program is capable of identifying, monitoring, and correcting the effects of boric corrosion on the intended function of components that may be exposed to borated water leakage, because the staff has confirmed that the program is consistent with the recommendations GALL AMP XI.M10 and the program is updated to account for relevant operating The staff finds that the Boric Acid Corrosion Program can be expected to ensure that the and components within the scope of the program will continue to perform their intended function:s consistent with the CLB for the period of extended operation. I, . I The staff confirmed that the "operating experience" program element satisfies the criterion qefined in the GALL Report and in SRP-LR Section A1.2.3.1 o. The staff finds this program element acceptable. I' UFSAR Supplement. LRA Section A2.1.4, provides the applicant'sUFSAR Supplement fon the Boric Acid Corrosion Program. The staff confirmed that the applicant's UFSAR Supplement' summary description for this program conforms to the staffs recommended UFSAR guidance found in SRP LR Table 3.1-2.' In LRA Section A5, Commitment No.4, the applicant committed to implement the Boric Acid Corrosion Program on an on-going basis during the period of extended operation. I; The staff finds that the applicant has provided an adequate summary description of the Boric Acid Corrosion Program as required by 10 CFR 54.21(d). .' Conclusion. On the basis of its audit and review of the applicant's Boric Acid Corrosion and the applicant's response to the RAI, the staff finds all program elements consistent witl1 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 1! reviewed the UFSAR Supplement for this AMP and concludes that the applicant has an adequate summary description of the program as required by 10 CFR 54.21(d). i II 3.0.3.1.2 Nickel Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure of Pressurized Water Reactors " Summary of Technical Information in the Application. LRA Section B.2.1.5 describes the existing Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program as being consistent to GALL AMP XI. M 11 A, Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors." . . The applicant stated that this program has been established to ensure that augmented inspections (lSI) of all nickel alloy vessel head penetration (VHP) nozzles welded to the upger reactor vessel (RV) head will continue to be performed as mandated by the interim requirerrents of NRC Order EA-03-009, "Issuance of Order Establishing Interim Inspection Requirements for Reactor Pressure Vessel Heads at Pressurized Water Reactors (PWRs)," as amended by the First Revision of the Order, or by any subsequent NRC requirements that may be to supersede the requirements of the Order. i: 3-12 Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report.In comparing the program elements in the applicant's program to those in the GALL AMP XI.M1 1A, the staff determined that the applicant's program elements are consistent with the recommendations of GALL AMP XI.M1 1A. The staff determined that the applicant committed to comply with all NRC Orders including bare head and non-destructive inspection at appropriate intervals, adhere to water chemistry guidelines, establish primary water stress corrosion cracking (PWSCC) susceptibility ranking and flaw evaluation, and establish repair and replacement procedures in accordance with NRC-approved American Society of Mechanical Engineers (ASME) Section XI Boiler and Pressure Vessel Code methods.The staff noted that revisions to 10 CFR 50.55a, "Codes and Standards" were issued in September of 2008, that change the requirements for inspection of nickel alloy welds.The applicant's LRA does not address the revisions to 10 CFR 50.55a because it was submitted in January 2008. The staff discussed this issue with the applicant who indicated in an e-mail dated January 14, 2009, that one of the changes impacts the AMP and that the changes have been incorporated in an interim revision to its ISI Program. The applicant further indicated that its scheduling database has been updated to reflect the inspection requirements of ASME Code Case N-729-1 and that a visual inspection is scheduled for Outage 1 R1 9 (in 2011) and that a non-destructive examination (NDE) has been scheduled for outage 20R (in 2013) both of which are in accordance with 10 CFR 50.55a and Code Case N-729-1 through the 2013 refueling outage.The applicant further indicated that the changes do not impact the text in the LRA describing the program and that the text will only slightly change based on the revised requirements. The applicant further indicated that the changes are scheduled to be completed by April 30, 2009 and that the changes will not be identified as exceptions to GALL AMP XI.M1 1A which is considered acceptable based on the discussion provided in the Federal Register Notice when the rule was revised. During a phone conversation on June 29, 2009, the applicant indicated that the changes identified above have been completed. Based on its review, the staff finds the applicant's implementation of the provisions of 10 CR 50.55a and ASME Code Case N-729-1, acceptable. Based on its review, the staff finds the applicant's Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program consistent with the program elements of GALL AMP XI.M1 1A, "Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program," and acceptable. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.5 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. Furthermore, the staff confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant stated that the effects of aging are effectively managed through objective evidence that shows that PWSCC of upper VHP nozzles is being adequately managed. The staff determined that the LRA provides examples of operating experience that provide objective evidence that the Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation. The 3-13 Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. In comparing the program elements in the applicant's program to those in the GALL AMP XI.M11A, the staff determined that the applicant's program elements are consistent with the recommendations of GALL AMP XI.M11A. The staff determined that the applicant committed to comply with all NRC Orders including bare head and non-destructive inspection at appropriate intervals, adhere to water chemistry guidelines, establish primary water stress corrosion cracking (PWSCC) susceptibility ranking and flaw evaluation, and establish repair and replacement procedures in accordance with NRC-approved American Society of Mechanical Engineers (ASME) Section XI Boiler and Pressure Vessel Code methods. The staff noted that revisions to 10 CFR 50.55a, "Codes and Standards" were issued in September of 2008, that change the requirements for inspection of nickel alloy welds. The applicant's LRA does not address the revisions to 10 CFR 50.55a because it was submitted in January 2008. The staff discussed this issue with the applicant who indicated in an e-mail dated January 14, 2009, that one of the changes impacts the AMP and that the changes have been incorporated in an interim revision to its lSI Program. The applicant further indicated that its scheduling database has been updated to reflect the inspection requirements of ASME Code Case N-729-1 and that a visual inspection is scheduled for Outage 1 R19 (in 2011) and that a destructive examination (NDE) has been scheduled for outage 20R (in 2013) both of which are in accordance with 10 CFR 50.55a and Code Case N-729-1 through the 2013 refueling outage. The applicant further indicated that the changes do not impact the text in the LRA describing the program and that the text will only slightly change based on the revised requirements. The applicant further indicated that the changes are scheduled to be completed by April 30, 2009 and that the changes will not be identified as exceptions to GALL AMP XI.M11A which is considered acceptable based on the discussion provided in the Federal Register Notice when the rule was revised. During a phone conversation on June 29, 2009, the applicant indicated that the changes identified above have been completed. Based on its review, the staff finds the applicant's implementation of the provisions of 10 CR 50.55a and ASME Code Case N-729-1, acceptable. Based on its review, the staff finds the applicant's Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program consistent with the program elements of GALL AMP XI.M11A, "Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program," and acceptable. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.5 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. Furthermore, the staff confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The applicant stated that the effects of aging are effectively managed through objective evidence that shows that PWSCC of upper VHP nozzles is being adequately managed. The staff determined that the LRA provides examples of operating experience that provide objective evidence that the Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation. The 3-13 LRA states that during the first refueling outage (Fall 2005) after head replacement (with PWSCC resistant nozzles) in 2003, a one hundred % bare metal and control rod drive (CRD) flange ,visual inspection detected minor staining and boron film deposits, but no corrosion of the head was detected. The cause of the deposits was a leaking bolted CRD flange connection and not PWSCC.The staff determined that the documentation provided by the applicant during the onsite review supported the applicant's statements regarding operating experience and confirms that the iplant-specific operating experience did not reveal any degradation not bounded by industry experience. 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. LRA Section A.2.1.5, provides the applicant's UFSAR Supplement for the Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program. The staff confirmed that the applicant's UFSARSupplement summary description for this program conforms to the staffs recommended UFSAR Supplement guidance found in SRP-LR, Table 3.1-2.In LRA Section A.5, Commitment No. 5, the applicant committed to the continued implementation of the existing Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program during the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program, the staff finds all program elements consistent with the GALL Report. The staffconcludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d).3.0.3.1.3 Bolting Integrity Summary of Technical Information in the Application. LRA Section B.2.1.7 describes the existing Bolting Integrity Program as being consistent with GALL AMP XI.M18, "Bolting Integrity." The applicant stated that the program manages the loss of material due to general, pitting and crevice corrosion, microbiologically-influenced corrosion and loss of preload-due to thermal effects, gasket creep, and self-loosening, by incorporating NRC and industry recommendations in NUREG-1339, "Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants," EPRI TR-104213, "Bolted Joint Maintenance & Applications Guide," and EPRI NP-5769, "Degradation and Failure of Bolting in Nuclear Power Plants."The applicant stated that the program is supplemented by several other AMPs which carry out the specifications identified in the program. The supplemental programs include the Structures 3-14 LRA states that during the first refueling outage (Fall 2005) after head replacement (with PWSCC resistant nozzles) in 2003, a one hundred % bare metal and control rod drive (CRD) flange,1visual inspection detected minor staining and boron film deposits, but no corrosion of the head was detected. The cause of the deposits was a leaking bolted CRD flange connection and not PWSCC. The staff determined that the documentation provided by the applicant during the onsite re\(iew supported the applicant's statements regarding operating experience and confirms that the specific operating experience did not reveal any degradation not bounded by industry experience. The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1 O. The staff finds this program element acceptable. UFSAR Supplement. LRA Section A.2.1.5, provides the applicant's UFSAR Supplement for the Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program. The staff confirmed that the applicant's UFSAR I Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in SRP-LR, Table 3.1-2. In LRA Section A.5, Commitment No.5, the applicant committed to the continued implementation of the existing Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program during the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Nickel-Alloy Penetration i: Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects_ of aging will be adequately** managed so that the intended function( s) will be maintained consistent with the CLB for the period of extended operation as required by 10 CFR 54.21 (a)(3). The staff also reviewed the Supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21 (d). 3.0.3.1.3 Bolting Integrity Summary of Technical Information in the Application. LRA Section B.2.1. 7 describes the existing Bolting Integrity Program as being consistent with GALL AMP XI.M18, "Bolting Integrity." The applicant stated that the program manages the loss of material due to general, pitting crevice corrosion, microbiologically-influenced corrosion and loss of preload due to thermal effects, gasket creep, and self-loosening, by incorporating NRC and industry recommendations in NUREG-1339, "Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Power Plants," EPRI TR-104213, "Bolted Joint Maintenance & Applications Guide," and EPRI NP-5769, "Degradation and Failure of Bolting in Nuclear Power Plants." The applicant stated that the program is supplemented by several other AMPs which carry out the specifications identified in the program. The supplemental programs include the Structures 3-14 Monitoring Program, ASME Section Xl Subsection IWE, ASME Section Xl Subsection IWF, Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems, and External Surfaces Monitoring Programs.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report.The staff reviewed the applicant's on-site documentation supporting the applicant's conclusion that the program elements are consistent with the elements in the GALL report. The staff also interviewed the applicant's technical staff and reviewed on-site documents. In comparing the program elements in the applicant's program to those in GALL AMP XI.M.18, the staff determined that the applicant's program elements are consistent with the recommendations of GALL AMP XI.M18, but also identified a possible exception to the"monitoring and trending" program element. The staff determined that the GALL recommendation concerning leak rate to be monitored on a particularly defined schedule was not specifically addressed in the applicant's program, and questioned whether it should be identified as an exception. In RAI B.2.1.7-1, dated October 7, 2008, the staff requested the applicant provide additional information on the applicant's leak rate monitoring schedule.In its response to the RAI, dated October 30, 2008, the applicant stated that it agrees with the staff's position that the leak rate monitoring issue should be identified as an exception to the GALL Report "monitoring and trending" program element. The applicant submitted this exception crediting its current corrective action program and leak detection process for meeting the recommendations of the GALL Report "monitoring and trending" program element.Furthermore, the applicant stated that in cases of leakage on bolting connections for pressure retaining components (not covered by ASME Section XI), the inspection frequency is determined by engineering evaluation of the problem through the corrective action program. The applicant stated that this is achieved through the use of periodic engineering walkdowns and equipment maintenance activities. Once a leak is identified, the issue is documented in the corrective action program and frequency of follow up inspections is assigned based on the evaluation of the problem. The applicant further stated that, for any leak, an evaluation is completed to determine the actions required based on the severity of the leak and the potential to impact normaloperations and safety. Furthermore, if the leak rate changes, further evaluation is performed to determine the actions required.Based on its review, the staff finds the applicant's response to RAI B.2.1.7-1 acceptable because the applicant submitted an exception to the GALL Report crediting its current corrective actionprogram and leak detection process for meeting the recommendation of GALL AMP XI.M18"monitoring and trending" program element. The staff also finds the exception acceptable. The staff's concern described in RAI B.2.1.7-1 is resolved.The staff noted that the Bolting Integrity Program is implemented through plant procedures that are based on NRC approved guidance and that inspections are conducted to manage the loss of material due to general, pitting and crevice corrosion, microbiologically-influenced corrosion and loss of preload due to thermal effects, gasket creep, and self-loosening. Based on its review, the staff finds the applicant's Bolting Integrity Program consistent with the program elements of GALL AMP XI.M18, "Bolting Integrity," and acceptable. 3-15 Monitoring Program, ASME Section XI Subsection IWE, ASME Section XI Subsection IWF, Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems, and External Surfaces Monitoring Programs. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the applicant's on-site documentation supporting the applicant's conclusion that the program elements are consistent with the elements in the GALL report. The staff also interviewed the applicant's technical staff and reviewed on-site documents. In comparing the program elements in the applicant's program to those in GALL AMP XLM.18, the staff determined that the applicant's program elements are consistent with the recommendations of GALL AMP XLM18, but also identified a possible exception to the "monitoring and trending" program element. The staff determined that the GALL recommendation concerning leak rate to be monitored on a particularly defined schedule was not specifically addressed in the applicant's program, and questioned whether it should be identified as an exception. In RAI B.2.1.7-1, dated October 7,2008, the staff requested the applicant provide additional information on the applicant's leak rate monitoring schedule. In its response to the RAI, dated October 30, 2008, the applicant stated that it agrees with the staff's position that the leak rate monitoring issue should be identified as an exception to the GALL Report "monitoring and trending" program element. The applicant submitted this exception crediting its current corrective action program and leak detection process for meeting the recommendations of the GALL Report "monitoring and trending" program element. Furthermore, the applicant stated that in cases of leakage on bolting connections for pressure retaining components (not covered by ASME Section XI), the inspection frequency is determined by engineering evaluation of the problem through the corrective action program. The applicant stated that this is achieved through the use of periodic engineering walkdownsand equipment maintenance activities. Once a leak is identified, the issue is documented in the corrective action program and frequency of follow up inspections is assigned based on the evaluation of the problem. The applicant further stated that, for any leak, an evaluation is completed to determine the actions required based on the severity of the leak and the potential to impact normal operations and safety. Furthermore, if the leak rate changes, further evaluation is performed to determine the actions required. Based on its review, the staff finds the applicant's response to RAI B.2.1. 7 -1 acceptable because the applicant submitted an exception to the GALL Report crediting its current corrective action program and leak detection process for meeting the recommendation of GALL AMP XLM18 "monitoring and trending" program element. The staff also finds the exception acceptable. The staff's concern described in RAI B.2.1.7-1 is resolved. The staff noted that the Bolting Integrity Program is implemented through plant procedures that are based on NRC approved guidance and that inspections are conducted to manage the loss of material due to general, pitting and crevice corrosion, microbiologically-influenced corrosion and loss of preload due to thermal effects, gasket creep, and self-loosening. Based on its review, the staff finds the applicant's Bolting Integrity Program consistent with the program elements of GALL AMP XI.M18, "Bolting Integrity," and acceptable. 3-15 Operatinq Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.7 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant stated that the operating experience related to Bolting Integrity did not show an adverse trend in performance. Furthermore, the applicant stated that all cases of bolting degradation were identified and corrective actions were implemented prior to loss of system intended functions. The staff reviewed operating experience reports, including a sample of issue reports. In one report, the applicant stated that an event occurred in 2002, where loose nuts were discovered on the decay heat removal pump. The staff determined that proper corrective actions were taken to address the issue, including an action requiring the inspection of a sample of safety related 1 land non safety related bolts or nuts. Additionally, an event occurred in 2005 where leakage was found on the exhaust manifold of the diesel generator. A faulty gasket led to improper closure, and as a result engine oil was found to be leaking from the exhaust manifold cover. The staff determined that proper corrective actions were taken to address the issue, including initiatives to determine the cause of the failure, multiple actions to correct the issue, and proper monitoring. 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. LRA Section A.2.1.7 provides the applicant's UFSAR Supplement fori the Bolting Integrity Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR.In LRA Section A.5, Commitment No. 7, the applicant committed to the ongoing implementation of the Bolting Integrity Program on an on-going basis during the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Bolting Integrity Program as required by 10 CFR 54.21(d).Conclusion. On the basis of its audit and review of the applicant's Bolting Integrity Program and the applicant's response to the RAI, the staff finds those program elements the applicant claimed consistency with the GALL report, are consistent. The staff reviewed the response to the RAI and finds it acceptable. The staff confirmed a previously unidentified exception to the "monitoring and trending" program element concerning the applicant's leak rate monitoring schedule. The s taff reviewed the exception and its justification and finds that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. The staff concluded that the applicant demonstrated that the effects of aging will be adequately managed so that intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d).3-16 Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.7 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The applicant stated that the operating experience related to Bolting Integrity did not show an adverse trend in performance. Furthermore, the applicant stated that all cases of bolting degradation were identified and corrective actions were implemented prior to loss of system intended functions. The staff reviewed operating experience reports, including a sample of issue reports. In one report, the applicant stated that an event occurred in 2002, where loose nuts were on the decay heat removal pump. The staff determined that proper corrective actions were taken to address the issue, including an action requiring the inspection of a sample of safety relatedlland non safety related bolts or nuts. Additionally, an event occurred in 2005 where leakage was found on the exhaust manifold of the diesel generator. A faulty gasket led to improper closure, and as a result engine oil was found to be leaking from the exhaust manifold cover. The staff determined that proper corrective actions were taken to address the issue, including initiatives to detertnine the cause of the failure, multiple actions to correct the issue, and proper monitoring. The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1 O. The staff finds this program element acceptable. U FSAR Supplement. LRA Section A.2.1. 7 provides the applicant's U FSAR Supplement for ll the Bolting Integrity Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR. In LRA Section A.5, Commitment No.7, the applicant committed to the ongoing implementation of the Bolting Integrity Program on an on-going basis during the period of extended operation, The staff finds that the applicant has provided an adequate summary description of the Bolting Integrity Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Bolting Integrity Program and the applicant's response to the RAI, the staff finds those program elements the applicant d'aimed consistency with the GALL report, are consistent. The staff reviewed the response to the RAI and finds it acceptable. The staff confirmed a previously unidentified exception to the "monitorililg and trending" program element concerning the applicant's leak rate monitoring schedule. The si taff reviewed the exception and its justification and finds that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. The staff concluded that the applicant demonstrated that the effects of aging will be adequately managed so that intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a){3). The staff also reviewed the UFSAR supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d). 3-16 3.0.3.1.4 Steam Generator Tube Integrity Summary of Technical Information in the Application. LRA Section B.2.1.8 describes the existing Steam Generator Tube Integrity Program as being consistent with GALL AMP XI.M19, "Steam Generator Tube Integrity." The applicant stated that the program establishes the operation, maintenance, testing, inspection and repair of the steam generators to ensure that Technical Specification surveillance requirements, ASME Code requirements and the Maintenance Rule (10 CFR 50.65) performance criteria are met. The applicant also stated that the program provides for identifying, maintaining and protecting the steam generator design and licensing bases and implements NEI 97-06,"Steam Generator Program Guidelines,"which provides a framework for prevention, inspection, evaluation, repair and leakage monitoring measures.The applicant also stated that it will replace the original Once-Through Steam Generators (OTSGs) with enhanced OTSGs prior to the period of extended operation and that this decision was made based on industry and plant experience with tube degradation. The applicant statedthat the new OTSGs have improved design features including Alloy 690 tubes and will have a design life of 40 years, which along with the Steam Generator Tube Integrity Program will be effective in assuring that the intended functions will be maintained consistent with the CLB for the period of extended operation. The applicant stated that the Steam Generator Tube Integrity Program will continue when the new OTSGs are installed. Staff Evaluation. During its review, the staff reviewed the applicant's claim of consistency with the GALL Report.In comparing the program elements in the applicant's program to those in GALL AMP XI.M19, the staff determined that the applicant's program elements are consistent with the recommendations of GALL AMP XI.M19.GALL Report AMP XI.M19 recommends preventative measures to mitigate degradation phenomena, assessment of degradation mechanisms, inservice inspection of steam generator tubes to detect degradation, evaluation and plugging or repair, and leakage monitoring to maintain the structural and leakage integrity of the pressure boundary.The LRA states that the program is also based upon NEI 97-06, which includes an assessment of degradation mechanisms and considers operating experience from similar steam generators to identify degradation mechanisms. For each mechanism, the EPRI guidelines associated with NEI 97-06 define the inspection techniques, measurement uncertainty, and the sampling strategy.EPRI guidelines associated with NEI 97-06 provide criteria for the qualification of personnel, specific techniques, and the associated acquisition and analysis of data. This includes procedures, probe selection, analysis protocols, and reporting criteria. The performance criteria in NEI 97-06 pertain to structural integrity, accident-induced leakage, and operational leakage. A Steam Generator Tube Integrity Program, as defined in NEI 97-06, includes guidance on assessment of degradation mechanisms, inspection, tube integrity assessment, maintenance, plugging, repair, leakage monitoring, and procedures for monitoring and controlling secondary-side and primary-side water chemistry. The staff finds the use of GALL AMP XI.M.19 and NEI 97-06 acceptable for managing aging of steam generator tubes and other components that can affect tube integrity. 3-17 3.0.3.1.4 Steam Generator Tube Integrity Summary of Technical Information in the Application. LRA Section B.2.1.8 describes the existing Steam Generator Tube Integrity Program as being consistent with GALL AMP XI.M19, "Steam Generator Tube Integrity." The applicant stated that the program establishes the operation, maintenance, testing, inspection and repair of the steam generators to ensure that Technical Specification surveillance requirements, ASME Code requirements and the Maintenance Rule (10 CFR 50.65) performance criteria are met. The applicant also stated that the program provides for identifying, maintaining and protecting the steam generator design and licensing bases and implements NEI 97-06, "Steam Generator Program Guidelines,""\'vhich provides a framework for prevention, inspection, evaluation, repair and leakage monitoring measures. The applicant also stated that it will replace the original Once-Through Steam Generators (OTSGs) with enhanced OTSGs prior to the period of extended operation and that this decision was made based on industry and plant experience with tube degradation. The applicant stated that the new OTSGs have improved design features including Alloy 690 tubes and will have a design life of 40 years, which along with the Steam Generator Tube Integrity Program will be effective in assuring that the intended functions will be maintained consistent with the CLB for the period of extended operation. The applicant stated that the Steam Generator Tube Integrity Program will continue when the new OTSGs are installed. Staff Evaluation. During its review, the staff reviewed the applicant's claim of consistency with the GALL Report. In comparing the program elements in the applicant's program to those in GALL AMP XI.M19, the staff determined that the applicant's program elements are consistent with the recommendations of GALL AMP XI.M19. . GALL Report AMP XI.M19 recommends preventative measures to mitigate degradation phenomena, assessment of degradation mechanisms, inservice inspection of steam generator tubes to detect degradation, evaluation and plugging or repair, and leakage monitoring to maintain the structural and leakage integrity of the pressure boundary. The LRA states that the program is also based upon NEI 97-06, which includes an assessment of degradation mechanisms and considers operating experience from similar steam generators to identify degradation mechanisms. For each mechanism, the EPRI guidelines associated with NEI 97-06 define the inspection techniques, measurement uncertainty, and the sampling strategy. EPRI guidelines associated with NEI 97-06 provide criteria for the qualification of personnel, specific techniques, and the associated acquisition and analysis of data. This includes procedures, probe selection, analysis protocols, and reporting criteria. The performance criteria in NEI 97-06 pertain to structural integrity, accident-induced leakage, and operational leakage. A Steam Generator Tube Integrity Program, as defined in NEI 97-06, includes guidance on assessment of degradation mechanisms, inspection, tube integrity assessment, maintenance, plugging, repair, leakage monitoring, and procedures for monitoring and controlling side and primary-Side water chemistry. The staff finds the use of GALL AMP XI.M.19 and NE197-06 acceptable for managing aging of steam generator tubes and other components that can affect tube integrity. 3-17 Based on its review, the staff finds the applicant's Steam Generator Tube Integrity Program consistent with the program elements of GALL AMP XI.M19, "Steam Generator Tube Integrity." Operatinq Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.8. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report.The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant stated that the steam generators will be replaced prior to the period of extended operation. The applicant provided three examples of site-specific operating experience to demonstrate effectiveness of the program as follows: (1) Widespread inside diameter intergranular attack (ID IGA) was identified in the early 1980s, mostly near the upper end of the OTSG tubing. The degradation was determined to have occurred during a chemistry excursion while the plant was in a shutdown condition. Repairs were performed using a kinetic expansion process that formed a new tube to tubesheet joint within the upper tubesheet. The repair was reviewed and approved by the NRC in 1983. Since that time, TMI-1 has specified inspection acceptance criteria and leakage assessment methodology for the TMI-1 OTSGs kinetic expansion joints that is unique to TMI-I. This inspection acceptance criteria and leakage assessment methodology has been reviewed and accepted by the NRC. During refueling outage 16 (Fall 2005), the kinetic expansion joints were inspected. These inspections found no growth of flaws in the kinetic expansion joints, and no trend of ongoing degradation 'due to ID IGA.(2) TMI-l will replace the OTSGs with enhanced OTSGs prior to the period of extended operation. This decision was made based on industry and TMI-1 experience with tube degradation. During refueling outage 16 (Fall 2005), 100 tubes in A OTSG and 106 tubes in B OTSG were plugged due to unacceptable indications. The inspections during this outage concluded that groove IGA, primary water stress corrosion cracking (PWSCC), outside diameter stress corrosion cracking (ODSCC) are active damage mechanisms. The results of TMI-1 tube inspections indicate increasing tube degradation and the probability of mid-cycle outages for inspection prior to the end of the current license. Currently, the A OTSG has 1661 plugged tubes and 247 sleeved tubes are in service. The B OTSG has 971 plugged tubes and 252 sleeved tubes are in service. The degradation mechanisms that have been identified historically in the current OTSGs include PWSCC, ID IGA, intergranular stress corrosion cracking (IGSCC), outside diameter intergranular attack (OD IGA), high cycle fatigue, OD SCC, tube-to-tube support plate wear fretting and severed plugged tube-to-tube wear. The new OTSGs will have a design life of 40 years, which along with the Steam Generator Tube Integrity program will be effective in assuring that the intended functions will be maintained consistent with the CLB for the period of extended operation. (3) TMI-1 has incorporated a technical specification (TS) change to implement the requirements of Generic Letter 2006-01 and the associated alternative T S requirements for ensuring tube integrity. Generic Letter 2006-01 required that all PWRs implement the alternative TS requirements or submit a description of their program for ensuring tube integrity. The Generic Letter indicated that existing TS may not be sufficient to ensure that steam generator tube integrity can be maintained in accordance with current licensing and 3-18 Based on its review, the staff finds the applicant's Steam Generator Tube Integrity Program consistent with the program elements of GALL AMP XI.M19, "Steam Generator Tube Integrity." Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.8. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The applicant stated that the steam generators will be replaced prior to the period of extenqed operation. The applicant provided three examples of site-specific operating experience to demonstrate effectiveness of the program as follows: (1) Widespread inside diameter intergranular attack (ID IGA) was identified in the early 1980s, mostly near the upper end of the OTSG tubing. The degradation was determined to have occurred during a chemistry excursion while the plant was in a shutdown condition .. Repairs were performed using a kinetic expansion process that formed a new tube to tubesheet joint within the upper tubesheet. The repair was reviewed and approved by the NRC in 1983. Since that time, TMI-1 has specified inspection acceptance criteria and leakage assessment methodology for the TMI-1 OTSGs kinetic expansion jOints that is unique to TMI-1. This inspection acceptance criteria and leakage assessment . methodology has been reviewed and accepted by the NRC. During refueling outage 16 (Fall 2005), the kinetic expansion joints were inspected. These inspections found no growth of flaws in the kinetic expansion joints, and no trend of ongoing degradation i1due to ID IGA. (2) TMI-1 will replace the OTSGs with enhanced OTSGs prior to the period of extended operation. This decision was made based on industry and TMI-1 experience with tube degradation. During refueling outage 16 (Fall 2005), 100 tubes in A OTSG and 106 tubes in B OTSG were plugged due to unacceptable indications. The inspections during this outage concluded that groove IGA, primary water stress corrosion cracking (PWSCC), outside diameter stress corrosion cracking (ObSCC) are active damage mechanisms. The results of TMI-1 tube inspections indicate increasing tube degradation and the probability of mid-cycle outages for inspection prior to the end of the current license. Currently, the A OTSG has 1661 plugged tubes and 247 sleeved tubes are in service. The B OTSGi1has 971 plugged tubes and 252 sleeved tubes are in service. The degradation mechanisms that have been identified historically in the current OTSGs include PWSCC, ID IGA, intergranular stress corrosion cracking (IGSCC), outside diameter attack (OD IGA), high cycle fatigue, OD SCC, tube-to-:otube support plate wear fretting and severed plugged tube-to-tube wear. The new OTSGs will have a design life of 40 years, which along with the Steam Generator Tube Integrity program will be effective in assuring that the intended functions will be maintained consistent with the CLB for the period of extended operation. (3) TMI-1 has incorporated a technical specification (TS) change to implement the requirements of Generic Letter 2006-01 and the associated alternative T S requiren;jlents for ensuring tube integrity. Generic Letter 2006-01 required that all PWRs implement the alternative TS requirements or submit a description of their program for ensuring tube integrity. The Generic Letter indicated that existing TS may not be sufficient to ensure that steam generator tube integrity can be maintained in accordance with current licensing and 3-18 design basis. The revised TS reflect a performance-based approach for ensuring tube integrity. The staff finds that implementation of the Steam Generator Tube Integrity Program will continue to effectively identify degradation prior to failure and that there is appropriate guidance for re-evaluation, repair, or replacement for locations where degradation is found. As a point of clarification, Generic Letter 2006-01 did not "require that all PWRs implement the alternative Technical Specification (TS) requirements or submit a description of their program for ensuring tube integrity," but "requested that addressees either submit a description of their program for ensuring SG tube integrity for the interval between inspections or adopt alternative TS requirements for ensuring SG tube integrity." 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. LRA Section A.2.1.8, provides the applicant's UFSAR Supplement for the Steam Generator Tube Integrity Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in SRP-LR, Table 3.1-2.In LRA Section A.5, Commitment No. 8, the applicant committed to the continued implementation of the existing Steam Generator Tube Integrity Program during the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Steam Generator Tube Integrity Program in the UFSAR Supplement as required by 10 CFR 54.21(d).Conclusion. On the basis of its review of the applicant's Steam Generator Tube Integrity Program, the staff finds all program elements consistent with the GALL Report. The staff also finds that the aging effects of SG tubes and tubes repairs will be adequately managed and that the AMP is acceptable for managing the aging effects of accessible SG secondary side internal components with the guidance of NEI 97-06. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d).3.0.3.1.5 Selective Leaching of Materials Summary of Technical Information in the Application. LRA Section B.2.1.19 describes the new Selective Leaching of Materials Program as being consistent with GALL AMP XI.M33, "Selective Leaching of Materials." The applicant stated that the program will be implemented prior to the period of extended operation and will consist of one-time inspections to determine if loss of material due to selective leaching is occurring. The applicant also stated that the scope of the program will include susceptible materials including gray cast iron and copper alloy with greater than 15% zinc and located in potentially aggressive environments that include raw water, closed cooling water, treated water, and soil.3-19 design basis. The revised TS reflect a performance-based approach for ensuring tube integrity. The staff finds that implementation of the Steam Generator Tube Integrity Program will continue to effectively identify degradation prior to failure and that there is appropriate guidance for evaluation, repair, or replacement for locations where degradation is found. As a point of clarification, Generic Letter 2006-01 did not "require that all PWRs implement the alternative Technical Specification (TS) requirements or submit a description of their program for ensuring tube integrity," but "requested that addressees either submit a description of their program for ensuring SG tube integrity for the interval between inspections or adopt alternative TS requirements for ensuring SG tube integrity." The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A1.2. 3.10. The staff finds this program element acceptable. UFSAR Supplement. LRA Section A2.1.8, provides the applicant's UFSAR Supplement for the Steam Generator Tube Integrity Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in SRP-LR, Table 3.1-2. In LRA Section A5, Commitment No.8, the applicant committed to the continued implementation of the existing Steam Generator Tube Integrity Program during the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Steam Generator Tube Integrity Program in the UFSAR Supplement as required by 10 CFR 54.21 (d). Conclusion. On the basis of its review of the applicant's Steam Generator Tube Integrity Program, the staff finds all program elements consistent with the GALL Report. The staff also finds that the aging effects of SG tubes and tubes repairs will be adequately managed and that the AMP is acceptable for managing the aging effects of accessible SG secondary side internal components with the guidance of NEI 97-06. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3) . . The staff also reviewed the UFSAR Supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d). 3.0.3.1.5 Selective Leaching of Materials Summary of Technical Information in the Application. LRA Section B.2.1.19 describes the new Selective Leaching of Materials Program as being consistent with GALL AMP XI.M33, "Selective Leaching of Materials." The applicant stated that the program will be implemented prior to the period of extended operation and will consist of one-time inspections to determine if loss of material due to selective leaching is occurring. The applicant also stated that the scope of the program will include susceptible materials including gray cast iron and copper alloy with greater than 15% zinc and located in potentially aggressive environments that include raw water, closed cooling water, treated water, and soil. 3-19 Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report.In comparing the program elements in the applicant's program to those in GALL AMP XI.M33, the staff determined that the applicant's program elements are consistent with the recommendations of GALL AMP XI.M33.LRA Section B.2.1.19 states that the program provides for visual inspections, hardness tests, and other appropriate examinations, to identify and confirm existence of the loss of material due to selective leaching. The applicant also stated that condition monitoring and expanded sampling will be utilized, as required, to ensure the components will perform as designed.Based on its review, the staff finds the applicant's Selective Leaching of Materials Program, consistent with the program elements of GALL AMP XI.M33, "Selective Leaching of Materials Program," and acceptable. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.19 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.LRA Section B.2.1.19 states that the Selective Leaching of Materials Program is a new program and there is no plant-specific program operating experience. However, the applicant also stated that the review of plant specific operating experience identified the dezincification of copper alloys containing greater than 15% zinc in treated water environments. Specifically, in December 2004, the applicant found dezincification occurred in a tubing cap of a test tee for a pressure gauge in the main steam system, and this condition contributed to the failure of the tubing cap. The applicant replaced the cap with stainless steel material, which is not susceptible to selective leaching. As part of the corrective action, the applicant replaced another cap on a companion gauge and conducted extent-of condition walkdowns in the immediate area of the failed cap, to determine if other components had similar dezincification degradation, and did not identify any discrepancies. 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. LRA Section A.2.1.19 provides the UFSAR Supplement for the Selective Leaching of Materials Program. The staff confirmed that the UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in SRP-LR Table 3.3-2.In LRA Section A.5, Commitment No. 19, the applicant committed to implement the Selectiye Leaching Program prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Selective Leaching of Materials Program as required by 10 CFR 54.21(d).3-20 Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. In comparing the program elements in the applicant's program to those in GALL AMP XI.M33, the staff determined that the applicant's program elements are consistent with the recommendations of GALL AMP XI.M33. LRA Section B.2.1.19 states that the program provides for visual inspections, hardness tests, and other appropriate examinations, to identify and confirm existence of the loss of material due to selective leaching. The applicant also stated that condition monitoring and expanded sampling will be utilized, as required, to ensure the components will perform as designed. Based on its review, the staff finds the applicant's Selective Leaching of Materials Program, consistent with the program elements of GALL AMP XI.M33, "Selective Leaching of Materials Program," and acceptable. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.19 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also that the applicant has addressed operating experience identified after the issuance of the GALL Report. LRA Section B.2.1.19 states that the Selective Leaching of Materials Program is a new program and there is no plant-specific program operating experience. However, the applicant also stated that the review of plant specific operating experience identified the dezincification of copper alloys containing greater than 15% zinc in treated water environments. Specifically, in December 2004, the applicant found dezincification occurred in a tubing cap of a test tee for a pressure gauge in the main steam system, and this condition contributed to the failure of the tubing cap. The applicant replaced the cap with stainless steel material, which is not susceptible to leaching. As part of the corrective action, the applicant replaced another cap on a companion gauge and conducted extent-of condition walkdowns in the immediate area of the failed cap, to determine if other components had similar dezincification degradation, and did not identify any discrepancies. The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP LR Section A1.2.3.1 O. The staff finds this program element acceptable. ' UFSAR Supplement. LRA Section A2.1.19 provides the UFSAR Supplement for the Selective Leaching of Materials Program. The staff confirmed that the UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement gui9ance found in SRP-LR Table 3.3-2. i: In LRA Section A5, Commitment No. 19, the applicant committed to implement the Leaching Program prior to the period of extended operation. ' The staff finds that the applicant has provided an adequate summary description of the Selective Leaching of Materials Program as required by 10 CFR 54.21(d). 3-20 Conclusion. On the basis of its audit and review of the applicant's Selective Leaching of Materials Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this program and concludes that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d). 3.0.3.1.6 ASME Section XI, Subsection IWL Summary of Technical Information in the Application. LRA Section B.2.1.25 describes the existing ASME Section Xl, Subsection IWL program as being consistent with GALL AMP XI.S2 "ASME Section Xl, Subsection IWL." The applicant stated that the ASME Section XI, Subsection IWL program implements examination requirements of the ASME Boiler and Pressure Vessel (B&PV) Code, Section Xl, Subsection IWL for reinforced and prestressed concrete containments (Class CC), 1992 Edition with the 1992 Addenda, as mandated in 10 CFR 50.55a, for managing loss of material (spalling, scaling) and cracking/freeze-thaw, cracking, loss of bond, and loss of material (spalling, scaling)/corrosion of embedded steel, cracking/expansion and reaction with aggregates, increase in porosity and permeability, cracking, loss of material (spalling, scaling)/aggressive chemical attack for concrete;loss of material/general, pitting, and crevice corrosion for tendon wires and end anchorage components, and loss of prestress/relaxation; shrinkage; creep; elevated temperature of the tendons.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report.In comparing the program elements in the applicant's program to those in GALL AMP XI.S2, thestaff determined that the applicant's program elements are consistent with the recommendations of GALL AMP XI.S2.Based on its review, the staff finds that the applicant's ASME Section Xl, Subsection IWL program provides assurance that aging of reinforced and prestressed concrete containment structures will be adequately managed. The staff also finds the applicant's ASME Section XI, Subsection IWL Program consistent with the program elements of GALL AMP XI.S2, "ASME Section Xl, Subsection IWL," and acceptable. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.25 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant stated that the operating experience of the ASME Section XI, Subsection IWL activities shows no adverse trend of program performance. LRA Section B.2.1.25 summarizes the 30th year (2005) surveillance results and corrective actions. The staff reviewed the summary of 25th year (2000) reactor building ISI inspection results and corrective actions, as well as some earlier results and corrective actions. The staff determined that the operating experience indicates 3-21 Conclusion. On the basis of its audit and review of the applicant's Selective Leaching of Materials Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this program and concludes that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d). 3.0.3.1.6 ASME Section XI, Subsection IWL Summary of Technical Information in the Application. LRA Section B.2.1.25 describes the eXisting ASME Section XI, Subsection IWL program as being consistent with GALL AMP XI,S2 "ASME Section XI, Subsection IWL." The applicant stated that the ASME Section XI, Subsection IWL program implements examination requirements of the ASME Boiler and Pressure Vessel (B&PV) Code, Section XI, Subsection IWL for reinforced and prestressed concrete containments (Class CC), 1992 Edition with the 1992 Addenda, as mandated in 10 CFR 50.55a, for managing loss of material (spalling, scaling) and cracking/freeze-thaw, cracking, loss of bond, and loss of material (spalling, scaling)/corrosion of embedded steel, cracking/expansion and reaction with aggregates, increase in porosity and permeability, cracking, loss of material (spalling, scaling)/aggressive chemical attack for concrete; loss of material/general, pitting, and crevice corrosion for tendon wires and end anchorage components, and loss of prestress/relaxation; shrinkage; creep; elevated temperature of the tendons. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. In comparing the program elements in the applicant's program to those in GALL AMP XI,S2, the staff determined that the applicant's program elements are consistent with the recommendations of GALL AMP XI,S2. B.ased on its review, the staff finds that the applicant's ASME Section XI, Subsection IWL program provides assurance that aging of reinforced and prestressed concrete containment structures will be adequately managed. The staff also finds the applicant's ASME Section XI, Subsection IWL Program consistent with the program elements of GALL AMP XI,S2, "ASME Section XI, Subsection IWL," and acceptable. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.25 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The applicant stated that the operating experience of the ASME Section XI, Subsection IWL activities shows no adverse trend of program performance. LRA Section B.2.1.25 summarizes the 30th year (2005) surveillance results and corrective actions. The staff reviewed the summary of 25th year (2000) reactor building lSI inspection results and corrective actions, as well as some earlier results and corrective actions. The staff determined that the operating experience indicates 3-21 that loss of material (spalling, scaling) and cracking/freeze-thaw, cracking, loss of bond, and loss of material (spalling, scaling)/corrosion of embedded steel, cracking/expansion and reaction with aggregates, increase in porosity and permeability, cracking, loss of material (spalling, scaling)/aggressive chemical attack for concrete; loss of material/general, pitting, and crevice corrosion for tendon wires and end anchorage components, and loss of prestress/relaxation; shrinkage; creep; elevated temperature of the tendons; are being adequately managed.The staff also determined that operating experience of the ASME Section Xl, Subsection IWL Program did not show any adverse trend in performance. The applicant's evaluation indicated that problems identified would not cause significant impact to.the safe operation of the plant, and adequate corrective actions were taken to prevent recurrence. The staff determined that the applicant provided appropriate guidance for re-evaluation, repair, or replacement for locations where degradation is found. The staff noted that the applicant performs periodic self-assessments of the ASME Section Xl, Subsection IWL program to identify the areas that need improvement to maintain the quality performance of the program.Based on its review, the staff finds that the applicant's administrative controls are effective in detecting age-related degradation and initiating corrective action.Based on its review, the staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A. 1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. LRA Section A. 2.1.25 provides the UFSAR Supplement for the ASME Section XI, Subsection IWL Program. The staff confirmed that the UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR.In LRA Section A.5, Commitment No. 25, the applicant credited the existing program on an ongoing basis.The staff finds that the applicant has provided an adequate summary description of the ASME Section XI, Subsection IWL Program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's ASME Section XI, Subsection IWL Program the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately , managed so that the intended 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 the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d). 3.0.3.1.7 10 CFR Part 50, Appendix J Summary of Technical Information in the Application. LRA Section B.2.1.27 describes the existing 10 CFR Part 50, Appendix J Program as being consistent with GALL AMP XI.S4 "10 CFR 50, Appendix J." The applicant stated that 10 CFR 50, Appendix J Program monitors leakage rates through the containment pressure boundary, including penetrations and access openings, and that containment leak rate tests assure that leakage through the primary containment and systems 3-22 that loss of material (spalling, scaling) and cracking/freeze-thaw, cracking, loss of bond, and loss of material (spalling, scaling)/corrosion of embedded steel, cracking/expansion and reaction with aggregates, increase in porosity and permeability, cracking, loss of material (spa/ling, scaling)/aggressive chemical attack for concrete; loss of material/general, pitting, and crevice corrosion for tendon wires and end anchorage components, and loss of prestress/relaxation; shrinkage; creep; elevated temperature of the tendons; are being adequately managed. The staff also determined that operating experience of the ASME Section XI, Subsection IWL Program did not show any adverse trend in performance. The applicant's evaluation indicated that problems identified would not cause significant impact to, the safe operation of the plant, and adequate corrective actions were taken to prevent recurrence. The staff determined that the applicant provided appropriate guidance for re-evaluation, repair, or replacement for locations where degradation is found. The staff noted that the applicant performs periodic self-assessments of the ASME Section XI, Subsection IWL program to identify the areas that need to maintain the quality performance of the program. Based on its review, the staff finds that the applicant's administrative controls are effective in detecting age-related degradation and initiating corrective action. Based on its review, the staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1 O. The staff finds this program element acceptable. UFSAR Supplement. LRA Section A. 2.1.25 provides the UFSAR Supplement for the ASME Section XI, Subsection IWL Program. The staff confirmed that the UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR. In LRA Section A.5, Commitment No. 25, the applicant credited the existing program on an ongoing basis. The staff finds that the applicant has provided an adequate summary description of the ASME Section XI, Subsection IWL Program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's ASME Section XI, IWL Program the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately I 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 the applicant has provided an adequate . summary description of the program as required by 10 CFR 54.21(d). 3.0.3.1.7 10 CFR Part 50, Appendix J Summary of Technical Information in the Application. LRA Section B.2.1.27 describes the existing 10 CFR Part 50, Appendix J Program as being consistent with GALL AMP XI.S4 "10 CFR 50, Appendix J." The applicant stated that 1 0 CFR 50, Appendix J Program monitors leakage rates through the containment pressure boundary, including penetrations and access openings, and that containment leak rate tests assure that leakage through the primary containment and systems 3-22 and components penetrating primary containment does not exceed acceptance criteria limits. The applicant stated that it uses Option B, the performance-based approach to implement the requirement of containment leak rate monitoring and testing.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report.In comparing the program elements in the applicant's program to those in GALL AMP XI.S4, the staff determined that the applicant's program elements are consistent with the recommendations of GALL AMP XI.S4.Based on its review, the staff finds that the applicant's 10 CFR Part 50, Appendix J Program provides assurance that leakage through the primary containment and system and components penetrating primary containment will be adequately managed. The staff also finds the applicant's 10 CFR Part 50, Appendix J Program consistent with the program elements of GALL AMP XI.S4,"10 CFR 50, Appendix J," and acceptable. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.27 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The staff identified one issue where additional information was requested from the applicant to complete its review. The issue concerns the measurement of leak rate tests. According to 10 CFR50, Appendix J, La (%/24 hours), the maximum allowable leakage rate at pressure Pa as specified in the TS, should be used as a measurement for the leak rate test. The staff noted that recent containment local leak rate tests (LLRT) were performed in 2001, 2003, 2005, and 2007, however, the applicant presented these results in term of SCCM (Standard Cubic Centimeters per minute). In RAI B.2.1.27-1, dated October 7, 2008, the staff requested that the applicant provide additional information ,concerning the leak rated test results. The staff requested that the leak rate test results be provided in terms of La.In its response to the RAI, dated October 30, 2008, the applicant presented the leak rate test results in terms of La, the maximum allowable leakage rate at pressure Pa as specified in the TS.For Type B and C tests, the allowable leakage rate is 0.6La. The staff noted that the test results indicated a positive trend in performance on LLRT, except that individual valves on occasion exceed the leakage acceptance test values and repairs were made in accordance with the program. The staff also noted that the test results indicated that the ILRT results are well under the acceptance criteria.Based on its review, the staff finds the applicant's response to RAI B.2.1.27-1 acceptable. The staff's concern described in RAI B.2.1.27-1 is resolved.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. 3-23 and components penetrating primary containment does not exceed acceptance criteria limits. The applicant stated that it uses Option B, the performance-based approach to implement the requirement of containment leak rate monitoring and testing. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. In comparing the program elements in the applicant's program to those in GALL AMP XI.S4, the staff determined that the applicant's program elements are consistent with the recommendations of GALL AMP XI.S4. Based on its review, the staff finds that the applicant's 10 CFR Part 50, Appendix J Program provides assurance that leakage through the primary containment and system and components penetrating primary containment wi" be adequately managed. The staff also finds the applicant's 10 CFR Part 50,Appendix J Program consistent with the program elements of GALL AMP XI.S4, "10 CFR 50, Appendix J," and acceptable. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.27 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The staff identified one issue where additional information was requested from the applicant to complete its review. The issue concerns the measurement of leak rate tests. According to 10 CFR 50, Appendix J, La (%/24 hours), the maximum a"owable leakage rate at pressure Pa as specified in the TS, should be used as a measurement for the leak rate test. The staff noted that recent containment local leak rate tests (LLRT) were performed in 2001, 2003, 2005, and 2007, however, the applicant presented these results in term of SCCM (Standard Cubic Centimeters per minute). In RAI B.2.1.27-1, dated October 7, 2008, the staff requested that the applicant provide additional information ,concerning the leak rated test results. The staff requested that the leak rate test results be provided in terms of La. In its response to the RAI, dated October 30,2008, the applicant presented the leak rate test results in terms of La, the maximum allowable leakage rate at pressure Pa as specified in the TS. For Type Band C tests, the a"owable leakage rate is 0.6La. The staff noted that the test results indicated a positive trend in performance on LLRT, except that individual valves on occasion exceed the leakage acceptance test values and repairs were made in accordance with the program. The staff also noted that the test results indicated that the ILRT results are we" under the acceptance criteria. Based on its review, the staff finds the applicant's response to RAI B.2.1.27-1 acceptable. The staff's concern described in RAI B.2.1.27-1 is resolved. The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1

o. The staff finds this program element acceptable.

3-23 UFSAR SuDplement. LRA Section A.2.1.27 provides the UFSAR Supplement for the 10 CFR Part 50, Appendix J Program. The staff confirmed that the UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR.In LRA Section A.5, Commitment No. 27, the applicant credited the existing program on an ongoing basis.The staff finds that the applicant has provided an adequate summary description of the 10 CFR Part 50, Appendix J Program as required by 10 CFR 54.21(d).Conclusion. On the basis of its audit and review of the applicant's 10 CFR Part 50, Appendix J Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended 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 UFS AR Supplement for this program and concludes that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d). 3.0.3.1.8 Protective Coating Monitoring and Maintenance Program Summary of Technical Information in the Application. LRA Section B.2.1.29 describes the existing Protective Coating Monitoring and Maintenance Program as being consistent with GALL AMP XI.S8, "Protective Coating Monitoring and Maintenance Program." The applicant stated that the program is not originally committed to RG 1.54 for Service Level 1 coatings because the plant was licensed prior to the issuance of this RG in 1973. The applicantalso stated that it is committed to a modified version of this RG, as responses to GL 98-04. the applicant further stated that the program is a "comparable program" as described in GALL AMP XI.S8.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report.In comparing the program elements in the applicant's program to those in GALL AMP XI.S8, the staff determined that the applicant's program elements are consistent with the recommendations of GALL AMP XI.S8.Based on its review, the staff finds the applicant's Protective Coating Monitoring and Maintenance Program consistent with the program elements of GALL AMP XI.S8, "Protective Coating Monitoring and Maintenance Program," and acceptable. Operatingq Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.29 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.3-24 UFSAR Supplement. LRA Section A.2.1.27 provides the UFSAR Supplement for the 10 CFR Part 50, Appendix J Program. The staff confirmed that the UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found'in the SRP-LR. In LRA Section A.5, Commitment No. 27, the applicant credited the existing program on an ongoing basis. The staff finds that the applicant has provided an adequate summary description of the 10 CFR Part 50, Appendix J Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's 10 CFR Part 50, Appendix J Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately II managed so that the intended functions will be maintained consistent with the CLB for the Reriod of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the Supplement for this program and concludes that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d). 3.0.3.1.8 Protective Coating Monitoring and Maintenance Program Summary of Technical Information in the Application. LRA Section B.2.1.29 describes the existing Protective Coating Monitoring and Maintenance Program as being consistent with GALL AMP XLS8, "Protective Coating Monitoring and Maintenance Program." The applicant stated that the program is not originally committed to RG 1.54 for Service Level 1 coatings because the plant was licensed prior to the issuance of this RG in 1973. The appli9ant also stated that it is committed to a modified version of this RG, as responses to GL 98-04. lifhe applicant further stated that the program is a "comparable program" as described in GALL AMP XLS8. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. In comparing the program elements in the applicant's program to those in GALL AMP XLS8', the staff determined that the applicant's program elements are consistent with the recommendations of GALL AMP XI.S8. Based on its review, the staff finds the applicant's Protective Coating Monitoring and Maintenance Program consistent with the program elements of GALL AMP XI.S8, "Protective Coating Monitoring and Maintenance Program," and acceptable. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.29 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirljl1ed that the applicant has addressed operating experience identified after the issuance of the GALL Report. 3-24 LRA Section B.2.1.29 states that demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that degradation of Service Level 1 protective coatings are being adequately managed. The applicant also stated that the Protective Coating Monitoring and Maintenance Program will be effective in assuring that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. The staff determined that the applicant's Protective Coating Monitoring and Maintenance Program has been effective in detecting degraded coatings at various areas within the containment during refueling outages. The staff noted that some areas with minor degraded coatings in containments during refueling outages is typical of industry experience. The applicant stated that if areas with degraded coating were detected, they were entered into its corrective action program and the degraded coatings were then removed, repaired, or deferred repair while maintaining the total degraded area below the permitted amount subject to detachment from the substrate during a loss of coolant accident (LOCA) to ensure post-accident operability of the emergency core cooling system (ECCS) suction strainers. The staff finds that the applicant's Protective Coating Monitoring and Maintenance Program has been effective in identifying, monitoring, and correcting the effects of protective coating degradation and revealed no degradation not bounded by industry experience. 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. LRA Section A.2.1.29 provides the UFSAR Supplement for the Protective Coating Monitoring and Maintenance Program. The staff confirmed that the UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR.In LRA Section A.5, Commitment No. 29, the applicant credited the existing program on an ongoing basis.The staff finds that the applicant has provided an adequate summary description of the Protective Coating Monitoring and Maintenance Program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its audit and review of the applicant's Protective Coating Monitoring and Maintenance Program, the staff finds all program elements consistent with the GALL Report.The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.1.9 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Summary of Technical Information in the Application. LRA Section B.2.1.30 describes the new Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program as being consistent with GALL AMP XI.E1, "Electrical Cables and Connections Not Subject to 10 CFR50.49 Environmental Qualification Requirements." 3-25 LRA Section B.2.1.29 states that demonstration that the effects of aging are effectively managed is aChieved through objective evidence that shows that degradation of Service Level 1 protective coatings are being adequately managed. The applicant also stated that the Protective Coating Monitoring and Maintenance Program will be effective in assuring that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. The staff determined that the applicant's Protective Coating Monitoring and Maintenance Program has been effective in detecting degraded coatings at various areas within the containment during refueling outages. The staff noted that some areas with minor degraded coatings in containments during refueling outages is typical of industry experience. The applicant stated that if areas with degraded coating were detected, they were entered into its corrective action program and the degraded coatings were then removed, repaired, or deferred repair while maintaining the total degraded area below the permitted amount subject to detachment from the substrate during a loss of coolant accident (LOCA) to ensure post-accident operability of the emergency core cooling system (ECCS) suction strainers. The staff finds that the applicant's Protective Coating Monitoring and Maintenance Program has been effective in identifying, monitoring, and correcting the effects of protective coating degradation and revealed no degradation not bounded by industry experience. The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP LR Section A1.2.3.1 O. The staff finds this program element acceptable. UFSAR Supplement. LRA Section A2.1.29 provides the UFSAR Supplement for the Protective Coating Monitoring and Maintenance Program. The staff confirmed that the UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR. In LRA Section A5, Commitment No. 29, the applicant credited the existing program on an ongoing basis. The staff finds that the applicant has provided an adequate summary description of the Protective Coating Monitoring and Maintenance Program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Protective Coating Monitoring and Maintenance Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.1.9 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Summary of Technical Information in the Application. LRA Section B.2.1.30 describes the new Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program as being consistent with GALL AMP XI.E1, "Electrical Cables and Connections Not Subject to 10 CFR50.49 Environmental Qualification Requirements." 3-25 The applicant stated that this program will be used to manage non-EQ cables and connections within the scope of license renewal that are subject to adverse localized environments. The applicant also stated that a sample of accessible electrical cables and connections installed in adverse environments will be visually inspected for signs of accelerated age-related degradation such as embrittlement, discoloration, cracking, or surface contamination. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report.In comparing the program elements in the applicant's program to those in GALL AMP XI.E1, the staff determined that the applicant's program elements are consistent with the recommendations of GALL AMP XI.E1, but also identified an issue for which the staff requested additional information. GALL AMP XI.E1 states that an adverse localized environment is a condition in a limited plant area that is significantly more severe than the specified service environment for the cable. In RAI B.2.1.30-1, dated October 07, 2008, the staff requested that the applicant provide additionalinformation to explain in detail how adverse localized environment is defined based on the most limiting designed service environment of cables (radiation, temperature, and moisture) within the scope of GALL AMP XI.E1.In its response to the RAI dated October 30, 2008, the applicant stated that general plant area ambient temperatures range from 700 F to 1400 F, and general plant area radiation doses range from 0 Rads to 6.57E06 Rads. The applicant also stated that the 60-year insulation design limits are used in conjunction with plant specific environmental design limits and plant operating experience to select general plant areas and localized areas in which to perform the visual inspections of a representative sample of cable and connection insulation. The applicant stated that a specific limiting temperature or radiation dose is not used as exclusion criteria to eliminate plant areas from consideration for walk down and subsequent cable and connection insulationinspections. The applicant also provided a draft procedure titled, "Inspection of non EQ cables and connections for managing adverse localized environments." In the draft procedure, the applicant provided ambient conditions for areas within the scope of license renewal. In its draft procedure, the applicant also stated that if information exists that identifies an area as "adverse," from a previous walk-down or plant operating experience (PIFs, corrective action reports), that this area is recorded as a potential adverse environment. The staff reviewed the procedure and found its approach to identifying adverse localized environment inadequate because the applicant's response did not demonstrate how plant specific cable specifications satisfies the GALL Report's definition of adverse localized environment, which states that an adverse localized environment is one which is significantly more severe than the specified service environment for the cable.In its supplemental response to the RAI dated January 30, 2009, the applicant stated that the thresholds for identifying adverse localized environments have been set at 1120 F and 5E04 Rads corresponding to TMI-1's limiting cable insulation materials, polyvinyl chloride (PVC) and tefloninsulations, respectively. The applicant further stated that the cable and connection insulations' 60-year design limits are taken from the EPRI Report 1013475, "Plant Support Engineering: License Renewal Electrical Handbook," dated February 2007, and that those limits will be incorporated into the implementing procedure for this AMP.Based on its review, the staff finds the applicant's responses to RAI B.2.1.30-1 acceptable because the applicant provided a numerical value of the most limiting designed service 3-26 The applicant stated that this program will be used to manage non-EO cables and connections within the scope of license renewal that are subject to adverse localized environments. The applicant also stated that a sample of accessible electrical cables and connections installed in adverse environments will be visually inspected for signs of accelerated age-related degradation such as embrittlement, discoloration, cracking, or surface contamination. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. In comparing the program elements in the applicant's program to those in GALL AMP XI.E1, the staff determined that the applicant's program elements are consistent with the recommendations of GALL AMP XI.E1, but also identified an issue for which the staff requested additional information. GALL AMP XI.E1 states that an adverse localized environment is a condition in a limited plant area that is significantly more severe than the specified service environment for the cable. In RAI B.2.1.30-1, dated October 07, 2008, the staff requested that the applicant provide additional information to explain in detail how adverse localized environment is defined based on the most limiting designed service environment of cables (radiation, temperature, and moisture) within the scope of GALL AMP XI.E1. In its response to the RAI dated October 30, 2008, the applicant stated that general plant area ambient temperatures range from 70 0 F to 140 0 F, and general plant area radiation doses range from 0 Rads to 6.57E06 Rads. The applicant also stated that the 60-year insulation design limits are used in conjunction with plant specific environmental design limits and plant operating experience to select general plant areas and localized areas in which to perform the visual inspections of a representative sample of cable and connection insulation. The applicant stated that a specific limiting temperature or radiation dose is not used as exclusion criteria to eliminate plant areas from consideration for walk down and subsequent cable and connection insulation inspections. The applicant also provided a draft procedure titled, "Inspection of non EO cables and connections for managing adverse localized environments." In the draft procedure, the applicant provided ambient conditions for areas within the scope of license renewal. In its draft procedure, the applicant also stated that if information exists that identifies an area as "adverse," from a previous walk-down or plant operating experience (PIFs, corrective action reports), that this area is recorded as a potential adverse environment. The staff reviewed the procedure and found its approach to identifying adverse localized environment inadequate because the applicant's response did not demonstrate how plant specific cable specifications satisfies the GALL Report's definition of adverse localized environment, which states that an adverse localized environment is one which is significantly more severe than the specified service environment for the cable. In its supplemental response to the RAI dated January 30, 2009, the applicant stated that the thresholds for identifying adverse localized environments have been set at 112 0 F and 5E04 Rads corresponding to TMI-1's limiting cable insulation materials, polyvinyl chloride (PVC) and teflon insulations, respectively. The applicant further stated that the cable and connection insulations' 60-year design limits are taken from the EPRI Report 1013475, "Plant Support Engineering: License Renewal Electrical Handbook," dated February 2007, and that those limits will be incorporated into the implementing procedure for this AMP. Based on its review, the staff finds the applicant's responses to RAI B.2.1.30-1 acceptable because the applicant provided a numerical value of the most limiting designed service 3-26 environment of cables (radiation and temperature) within the scope of GALL AMP XI.E1 which satisfies the GALL Report's definition of adverse localized environment, which states that an adverse localized environment is one which is significantly more severe than the specified service environment for the cable. The staffs concern described in RAI B.2.1.30-1 is resolved.Based on its review, the staff finds the Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program consistent with the program elements of GALL AMP XI.E1.Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.30 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant stated that in response to the cable insulation degradation experienced in an adverse localized environment at Turkey Point, it has evaluated plant configurations for the potential of heat damage to cable insulations. The applicant determined that the subject design configuration does not exist. Additionally, the applicant stated that it has identified several instances of potential age-related degradation of cables during the conduct of routine maintenance activities and dispositioned them using the corrective action process. The applicant further stated that in each case, engineering evaluations determined the cause of the apparent degradation, the effect on operability, and appropriate corrective actions, providing plant specific operating experience that provides objective evidence demonstrating effectiveness of the corrective action program in identifying and resolving potential aging related cable and connection insulation degradation issues. The staff verified that the applicant had appropriately identified the root causes of cable aging and took appropriate corrective actions. The staff reviewed the issue reports on these events that were provided by the applicant.Therefore, 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. LRA Section A.2.1.30 provides the applicant's UFSAR Supplement for the Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in SRP-LR.In LRA Section A.5, commitment No. 30, the applicant committed to implement this program prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Electrical Cables and Connections Not Subject To 10 CFR 50.49 Environmental Qualification Requirements Program as required by 10 CFR 54.21(d).Conclusion. On the basis of its audit and review of the applicant's Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program, the staff finds that those program elements for which the applicant claimed consistency with the 3-27 environment of cables (radiation and temperature) within the scope of GALL AMP XI.E1 which satisfies the GALL Report's definition of adverse localized environment, which states that an adverse localized environment is one which is significantly more severe than the specified service environment for the cable. The staff's concern described in RAI 8.2.1.30-1 is resolved. 8ased on its review, the staff finds the Electrical Cables and Connections Not Subject to 10 CFR S0.49 Environmental Qualification Requirements Program consistent with the program elements of GALL AMP XI.E1. Operating Experience. The staff reviewed the operating experience provided in LRA Section 8.2.1.30 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The applicant stated that in response to the cable insulation degradation experienced in an adverse localized environment at Turkey Point, it has evaluated plant configurations for the potential of heat damage to cable insulations. The applicant determined that the subject design configuration does not exist. Additionally, the applicant stated that it has identified several instances of potential age-related degradation of cables during the conduct of routine maintenance activities and dispositioned them using the corrective action process. The applicant further stated that in each case, engineering evaluations determined the cause of the apparent degradation, the effect on operability, and appropriate corrective actions, providing plant specific operating experience that provides objective evidence demonstrating effectiveness of the corrective action program in identifying and resolving potential aging related cable and connection insulation degradation issues. The staff verified that the applicant had appropriately identified the root causes of cable aging and took appropriate corrective actions. The staff reviewed the issue reports on these events that were provided by the applicant. Therefore, the staff confirmed* that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A1.2.3.1 O. The staff finds this program element acceptable. UFSAR Supplement. LRA Section A2.1.30 provides the applicant's UFSAR Supplement for the Electrical Cables and Connections Not Subject to 10 CFR S0.49 Environmental Qualification Requirements Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in SRP-LR. In LRA Section AS, commitment No. 30, the applicant committed to implement this program prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Electrical Cables and Connections Not Subject To 10 CFR 50.49 Environmental Qualification Requirements Program as required by 10 CFR S4.21(d). Conclusion. On the basis of its audit and review of the applicant's Electrical Cables and Connections Not Subject to 10 CFR S0.49 Environmental Qualification Requirements Program, the staff finds that those program elements for which the applicant claimed consistency with the 3-27 GALL Report are consistent. The staff also reviewed the applicant's responses to the RAI andfinds them acceptable. The staff concludes that the applicant has demonstrated that effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d).3.0.3.1.10 Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Summary of Technical Information in the Application. LRA Section B.2.1.32 describes the new Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program as being consistent with GALL AMP XI.E3, "Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements ." The applicant stated that the program manages inaccessible medium voltage cables that are exposed to significant moisture simultaneously with significant voltage. The applicant also statedthat inaccessible medium voltage cables subject to significant moisture and voltage will be tested as part of this program and that manholes associated with the in scope, non-EQ, inaccessible cables subject to significant moisture and voltage will be inspected, so that draining or other corrective actions can be taken. The applicant also stated that Inspections for water collection will be performed at a frequency of twice per year, in accordance with existing practices. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report.In comparing the program elements in the applicant's program to those in GALL AMP XI.E3, the staff determined that the applicant's program elements are consistent with the recommendations of GALL AMP XI.E3.Based on its review, the staff finds the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program consistent with the program elements of GALL AMP XI.E3, "Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements," and acceptable. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.32 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The staff reviewed operating experience and noted that inaccessible medium-voltage cables in certain manholes at Three Mile Island have experienced significant moisture (cable in standing water for more than few days). In addition, during a walk down, the staff found cables submerged under water in Manholes 7A and 7B which had already been inspected two weeks prior. The staff observed rusting on cable support structures and marking on the walls of these pairs of manholes which revealed evidence of a chronic water problem. The staff finds that this incident demonstrates that the corrective actions previously described by the applicant have not been properly implemented or were not adequate. The inspection and water removal frequency of twice 3-28 GALL Report are consistent. The staff also reviewed the applicant's responses to the RAI and finds them acceptable. The staff concludes that the applicant has demonstrated that effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d). 3.0.3.1.10 Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Summary of Technical Information in the Application. LRA Section B.2.1.32 describes the new Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program as being consistent with GALL AMP XLE3, "Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements ." The applicant stated that the program manages inaccessible medium voltage cables that are exposed to significant moisture simultaneously with significant voltage. The applicant also stated that inaccessible medium voltage cables subject to significant moisture and voltage will be tested as part of this program and that manholes associated with the in scope, non-EQ, inaccessible cables subject to significant moisture and voltage will be inspected, so that draining or other corrective actions can be taken. The applicant also stated that Inspections for water collection will be performed at a frequency of twice per year, in accordance with existing practices. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. In comparing the program elements in the applicant's program to those in GALL AMP XLE3, the staff determined that the applicant's program elements are consistent with the recommendations of GALL AMP XLE3. . Based on its review, the staff finds the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program consistent with the program elements of GALL AMP XLE3, "Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements," and acceptable. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.32 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The staff reviewed operating experience and noted that inaccessible medium-voltage cables in certain manholes at Three Mile Island have experienced significant moisture (cable in standing water for more than few days). In addition, during a walk down, the staff found cables submerged under water in Manholes 7 A and 78 which had already been inspected two weeks prior. The staff observed rusting on cable support structures and marking on the walls of these pairs of manholes which revealed evidence of a chronic water problem. The staff finds that this incident demonstrates that the corrective actions previously described by the applicant have not been properly implemented or were not adequate. The inspection and water removal frequency of twice 3-28 per year, as proposed by the applicant's Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program, may not be adequate to detect water accumulation in the manholes. In RAI B.2.1.32-1, dated October 07, 2008, the staff requested that the applicant provide additional information concerning the certification from the manufacturer on the submergence capability of the cables, or identify specific actions that will be taken to preclude the degradation of cables.In its response to the RAI dated October 30, 2008, the applicant stated that the frequency of the inspections will be adjusted based on inspection results and that this change in inspectionfrequency recognizes that the objective of the inspections, as a preventive action, is to keep the cables infrequently submerged, thereby minimizing their exposure to significant moisture. The applicant also stated that this change in inspection frequency also recognizes that a recurring inspection, set at the correct frequency, would result in the cables being submerged only as a result of event driven, rain and drain type occurrences. The staff determines that the applicant provided an adequate explanation because the identified actions are bounded by GALL AMP XI.E3. The staffs concern described in RAI B.2.1.32-1 is resolved.The staff has identified water in manholes as a generic, current operating plant issue inInformation Notice 2002-12, "Submerged Safety-Related Electrical Cables," dated March 21,* 2002, and Generic Letter 2007-01, "Inaccessible or Underground Power Cable Failures ThatDisable Accident Mitigation Systems Or Cause Plant Transients," dated February 7, 2007. The staff will address water in manholes, during the current period of operation, through the reactor oversight process in accordance with the requirements of 10 CFR Part 50.The staff determined that the Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program if implemented as described, would ensure that the aging affects on inaccessible medium-voltage cables, due to exposure to significant moisture and significant voltage, will be adequately managed during the period of extended operation, in accordance with the guidance contained in AMP XI.E3 of the GALL Report. The Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program is a new aging management program which will require the applicant to test the cables and to evaluate plant-specific 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 period of operation. The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and is SRP-LR Section A.1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. LRA Section A.2.1.32, provides the applicant's UFSAR Supplement for the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR.In LRA Section A.5, Commitment No. 32, the applicant committed to implement the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program prior to the period of extended operation. 3-29 per year, as proposed by the applicant's Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program, may not be adequate to detect water accumulation in the manholes. In RAI 8.2.1.32-1, dated October 07,2008, the staff requested that the applicant provide additional information concerning the certification from the manufacturer on the submergence capability of the cables, or identify specific actions that will be taken to preclude the degradation of cables. In its response to the RAI dated October 30, 2008, the applicant stated that the frequency of the inspections will be adjusted based on inspection results and that this change in inspection frequency recognizes that the objective of the inspections, as a preventive action, is to keep the cables infrequently submerged, thereby minimizing their exposure to significant moisture. The applicant also stated that this change in inspection frequency also recognizes that a recurring inspection, set at the correct frequency, would result in the cables being submerged only as a result of event driven, rain and drain type occurrences. The staff determines that the applicant provided an adequate explanation because the identified actions are bounded by GALL AMP XLE3; Thestaffs concern described in RAI 8.2.1.32-1 is resolved. 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, .2002, and 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 manholes, during the current period of operation, through the reactor oversight process in accordance with the requirements of 10 CFR Part 50. The staff determined that the Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program if implemented as described, would ensure that the aging affects on inaccessible medium-voltage cables, due to exposure to significant moisture and significant voltage, will be adequately managed during the period of extended operation, in accordance with the guidance contained in AMP XI.E3 of the GALL Report. The Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program is a new aging management program which will require the applicant to test the cables and to evaluate plant-specific 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 period of operation. The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and is SRP-LR Section A1.2.3.1 o. The staff finds this program element acceptable. UFSAR Supplement. LRA Section A2.1.32, provides the applicant's UFSAR Supplement for the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR. In LRA Section AS, Commitment No. 32, the applicant committed to implement the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program prior to the period of extended operation. 3-29 The staff finds that the applicant has provided an adequate summary description of the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program and the applicant's responses to the RAI, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.1.11 Environmental Qualification (EQ) of Electrical Components Summary of Technical Information in the Application. LRA, Section B.3.1.3, describes the existing Environmental Qualification (EQ) of Electric Components Program as being consistent with GALL AMP X.E1, "Electrical Qualification (EQ) of Electrical Components."The applicant stated that this program complies with 10 CFR 50.49, EQ of Electrical Equipment Important to Safety for Nuclear Power Plants and that all EQ equipment is included within the scope of license renewal. The applicant also stated that the program provides for maintenance of the qualified life for electrical equipment important to safety within the scope of 10 CFR 50.49.The applicant further stated that qualified life is determined for equipment within the scope of EQ program and appropriate actions such as reanalysis, replacement, or refurbishment are taken prior to or at the end of the qualified life of the equipment so that the aging limit is not exceeded.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report.The staff reviewed on-site bases documents related to the EQ of Electrical Components Program, and also reviewed plant implementing procedures, preventive maintenance work orders, and EQ program engineering change requests.In comparing the program elements in the applicant's program to those in GALL AMP X.E1, thestaff determined that the applicant's program elements are consistent with the recommendations of GALL AMP X.EI.Based on its review, the staff finds the applicant's EQ of Electric Components Program consistent with the program elements of GALL AMP X.E1, "EQ of Electrical Components." Operating Experience. The staff reviewed the operating experience provided in LRA Section B.3.1.3 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant stated that on September 15, 2006, it observed elevated building area temperatures due to an increase in outside ambient temperatures and equipment failures. The 3-30 The staff finds that the applicant has provided an adequate summary description of the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program and the applicant's responses to the RAI, the staff finds all prograni elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that effects of aging will be adequately managed so that the intended function{s) will be maintained consistent with the CLB for the period of extended operation as required by 10 CFR 54.21{a){3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21 (d). 3.0.3.1.11 Environmental Qualification (EQ) of Electrical Components Summary of Technical Information in the Application. LRA, Section B.3.1.3, describes the existing Environmental Qualification (EQ) of Electric Components Program as being consistent with GALL AMP X.E1, "Electrical.Qualification (EQ) of Electrical Components." The applicant stated that this program complies with 10 CFR 50.49, EQ of Electrical Equipment Important to Safety for Nuclear Power Plants and that all EQ equipment is included within the scope of license renewal. The applicant also stated that the program provides for maintenance of the qualified life for electrical equipment important to safety within the scope of 10 CFR 50.49. The applicant further stated that qualified life is determined for equipment within the scope of EQ program and appropriate actions such as reanalysis, replacement, or refurbishment are taken prior to or at the end of the qualified life of the equipment so that the aging limit is not exceeded. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed on-site bases documents related to the EQ of Electrical Components Program, and also reviewed plant implementing procedures, preventive maintenance work orders, and EQ program engineering change requests. In comparing the program elements in the applicant's program to those in GALL AMP X.E1, the staff determined that the applicant's program elements are consistent with the recommendations of GALL AMP X.E1. Based on its review, the staff finds the applicant's EQ of Electric Components Program consistent with the program elements of GALL AMP X.E1, "EQ of Electrical Components." Operating Experience. The staff reviewed the operating experience provided in LRA Section 8.3.1.3 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The applicant stated that on September 15, 2006, it observed elevated building area temperatures due to an increase in outside ambient temperatures and eqUipment failures. The 3-30 applicant also stated that proper evaluation of these conditions through the corrective action program demonstrated that the EQ of Electric Components Program was ensuring that EQ profiles were being met and immediate actions were taken to ensure that the elevated building area temperatures had not caused any components to exceed their qualified life. The applicant further stated that during the performance of maintenance activities, it identified and corrected conditions potentially adverse to maintaining the EQ qualification of components. On January 6, 2004, it identified a degraded EQ motor splice through the corrective action system. The applicant stated that it promptly evaluated the degraded splice for operability to ensure it met the requirements of the EQ file. The staff noted that during procurement activities, the applicant must demonstrate EQ qualification of components prior to installation. The applicant stated that on May, 18, 2004, a vendor supplied a component which had not had adequate EQ documentation. The applicant stated it delayed the installation, of the component until the proper EQ paperworkwas obtained. In reviewing operating experience in Assignment Report (AR) 00465770 in plant basis document, TM-PBD-AMP-B.3.1.3, the staff noted that the feed water valve FW-V-1 613/1 7B cabling was subject to 153.80 F (680 C) in the intermediate building. The EQ file ES-010T temperature for this zone is 110' F. The applicant concluded that there was not immediate danger of end of life. In RAI B.3.1.3-1, dated October 7, 2008, the staff requested that the applicant provide additional information explaining why there was no immediate danger of end of life of this cable and how this increased temperature affected the EQ of this cable.In its response to the RAI dated October 30, 2008, the applicant stated that it reviewed the EQ binder for the cables associated with the Feed Water valves FW-V-1 6B and FW-1 7B and found that the cables are normally de-energized 125 Vdc control cables and are conservatively qualified to 900 C/1 980 F for a 40-year plant life. The applicant concluded that the cables are qualified, with margin, for temperature in excess of the normal ambient conditions (1100 F) and with margin, for temperature in excess of the temporary excursion of 153.80 F resulting from the short-term unavailability of a ventilation fan. The applicant further stated that the cables were not exposed to temperature conditions that exceeded their qualification. Additionally, the cables are generally qualified with margin allowing for some fluctuation in environmental conditions without having impact to the cable qualification. The applicant also stated that based on the margin available in the qualification temperature, there was not immediate danger to the end of life for these cables, and there was no impact to the EQ or the qualified life of these cables.Based on its review, the staff finds that applicant's response to RAI B.3.1.3-1 acceptable because the cables are qualified to the environment of 1980 for a 40-year life and that the temporary increased temperature environment of 153.80 F resulting from the short-term unavailability of a ventilation fan did not affect the EQ of these cables. The staff's concern discussed in RAI B.3.1.3-1 is resolved.The staff finds that the operating experience 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 satisfies the criterion defined in the GALL Report and in SRP-LR Section A. 1.2.3.10. The staff finds this program element acceptable. 3-31 applicant also stated that proper evaluation of these conditions through the corrective action program demonstrated that the EO of Electric Components Program was ensuring that EO profiles were being met and immediate actions were taken to ensure that the elevated building area temperatures had not caused any components to exceed their qualified life. The applicant further stated that during the performance of maintenance activities, it identified and corrected conditions potentially adverse to maintaining the EO qualification of components. On January 6, 2004, it identified a degraded EO motor splice through the corrective action system. The applicant stated that it promptly evaluated the degraded splice for operability to ensure it met the requirements of the EO file. The staff noted that during procurement activities, the applicant must demonstrate EO qualification of components prior to installation. The applicant stated that on May, 18, 2004, a vendor supplied a component which had not had adequate EO documentation. The applicant stated it delayed the installation' of the component until the proper EO paperwork was obtained. In reviewing operating experience in Assignment Report (AR) 00465770 in plant basis document, TM-PBD-AMP-B.3.1.3, the staff noted that the feed water valve FW-V-16B/17B cabling was subject to 153.8° F (68° C) in the intermediate building. The EO file ES-010T temperature for this zone is 110° F. The applicant concluded that there was not immediate danger of end of life. In RAI B.3.1.3-1, dated October 7, 2008, the staff requested that the applicant provide additional information explaining why there was no immediate danger of end of life of this cable and how this increased temperature affected the EO of this cable. In its response to the RAI dated October 30, 2008, the applicant stated that it reviewed the EO binder for the cables associated with the Feed Water valves FW-V-16B and FW-17B and found that the cables are normally de-energized 125 Vdc control cables and are conservatively qualified to 90° C/198° F for a 40-year plant life. The applicant concluded that the cables are qualified, with margin, for temperature in excess of the normal ambient conditions (110° F) and with margin, for temperature in excess of the temporary excursion of 153.8° F resulting from the short-term unavailability of a ventilation fan. The applicant further stated that the cables were not exposed to temperature conditions that exceeded their qualification. Additionally, the cables are generally qualified with margin allowing for some fluctuation in environmental conditions without having . impact to the cable qualification. The applicant also stated that based on the margin available in the qualification temperature, there was not immediate danger to the end of life for these cables, and there was no impact to the EO or the qualified life of these cables. Based on its review, the staff finds that applicant's response to RAI B.3.1.3-1 acceptable because the cables are qualified to the environment of 198° for a 40-year life and that the temporary increased temperature environment of 153.8° F resulting from the short-term unavailability of a ventilation fan did not affect the EO of these cables. The staff's concern discussed in RAI B.3.1.3-1 is resolved. The staff finds that the operating experience identified above and those identified in program basis documents demonstrate that identification of program weakness and timely corrective actions as part of the EO 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 satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1 O. The staff finds this program element acceptable. 3-31 UFSAR Supplement. LRA Section A.3.1.3, provides the applicant's UFSAR Supplement for the EQ of Electric Components Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staffs recommended UFSAR Supplement guidance found in the SRP-LR.In LRA Section A.5, Commitment No. 39, the applicant credited the existing program on an ongoing basis.The staff finds that the applicant has provided an adequate summary description of the EQ of Electric Components Program as required by 10 CFR 54.21(d).Conclusion. On the basis of its audit and review of the applicant's EQ of Electrical Component Program and the applicant's response to the RAI, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2 AMPS That Are Consistent with the GALL Report with Exceptions or Enhancements In LRA Appendix B, the applicant identified the following AMPs that were, or will be, consistent with the GALL Report, with exceptions or enhancements:

  • ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" Water Chemistry* Reactor Head Closure Studs* Flow-Accelerated Corrosion* Open-Cycle Cooling Water System* Closed-Cycle Cooling Water System" Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems* Compressed Air Monitoring

  • Fire Protection" Fire Water System* Aboveground Steel Tanks* Fuel Oil Chemistry" Reactor Vessel Surveillance 3-32 UFSAR Supplement.

LRA Section A.3.1.3, provides the applicant's UFSAR Supplement for the EQ of Electric Components Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staffs recommended UFSAR Supplement guidance found in the SRP-LR. In LRA Section A.5, Commitment No. 39, the applicantcredited the existing program on an ongoing basis. The staff finds that the applicant has provided an adequate summary description of the EO of Electric Components Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's EO of Electrical Component Program and the applicant's response to the RAI, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21 (d). 3.0.3.2 AMPS That Are Consistent with the GALL Report with Exceptions or Enhancements In LRA Appendix B, the applicant identified the following AMPs that were, or will be, consistent with the GALL Report, with exceptions or enhancements:

  • ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD
  • Water Chemistry
  • Reactor Head Closure Studs
  • Flow-Accelerated Corrosion
  • Open-Cycle Cooling Water System
  • Closed-Cycle Cooling Water System
  • Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems

  • Compressed Air Monitoring
  • Fire Protection
  • Fire Water System
  • Aboveground Steel Tanks
  • Fuel Oil Chemistry
  • Reactor Vessel Surveillance 3-32 0 One-Time Inspection
  • Buried Piping and Tanks Inspection
  • External Surfaces Monitoring
  • Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components
  • Lubricating Oil Analysis" ASME Section XI, Subsection IWE* ASME Section XI, Subsection IWF* Structures Monitoring Program* Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits" Metal Enclosed Bus" Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements
  • Metal Fatigue of Reactor Coolant Pressure Boundary* Concrete Containment Tendon Prestress For AMPs that the applicant claimed are consistent with the GALL Report, with exceptions or enhancements, the staff performed an audit to confirm that those attributes or features of the program for which the applicant claimed consistency with the GALL Report were indeed consistent.

The staff also reviewed the exceptions and enhancements to the GALL Report to determine whether they were acceptable and adequate. The results of the staffs audit and reviews are documented in the following sections.3.0.3.2.1 ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Summary of Technical Information in the Application. LRA Section B.2.1.1, describes the existing ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program as being consistent, with exceptions, to GALL AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD." The applicant stated that this program provides inspections which are performed to manage cracking and loss of fracture toughness in Class 1, 2, and 3 piping and components within the scope of license renewal. The applicant also stated that this program provides for the periodic visual, surface, and volumetric examination and leakage testing of pressure-retaining piping and components including welds, pump casings, valve bodies, integral attachments, and pressure-retaining bolting.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exceptions to determine whether the program is adequate to manage the aging effects for which the LRA credits it.3-33* One-Time Inspection

  • Buried Piping and Tanks Inspection
  • External Surfaces Monitoring
  • Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components
  • Lubricating Oil Analysis
  • ASME Section XI, Subsection IWE
  • ASME Section XI, Subsection IWF
  • Structures Monitoring Program
  • Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits
  • Metal Enclosed Bus
  • Electrical Cable Connections Not Subject to 0 CFR 50.49 Environmental Qualification Requirements
  • Metal Fatigue of Reactor Coolant Pressure Boundary
  • Concrete Containment Tendon Prestress For AMPs that the applicant claimed are consistent with the GALL Report, with exceptions or enhancements, the staff performed an audit to confirm that those attributes or features of the program for which the applicant claim,ed consistency with the GALL Report were indeed consistent.

The staff also reviewed the exceptions and enhancements to the GALL Report to determine whether they were acceptable and adequate. The results of the staff's audit and reviews are documented in the following sections. 3.0.3.2.1 ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Summary of Technical Information in the Application. LRA Section B.2.1.1, describes the existing ASME SectionXllnservice Inspection, Subsections IWB, IWC, and IWD Program as being consistent, with exceptions, to GALL AMP XI.M1, "ASME Section Xllnservice Inspection, Subsections IWB, IWC, and IWD." The applicant stated that this program provides inspections which are performed to manage cracking and loss of fracture toughness in Class 1, 2, and 3 piping and components within the scope of license renewal. The applicant also stated that this program provides for the periodiC visual, surface, and volumetric examination and leakage testing of pressure-retaining piping and components including welds, pump casings, valve bodies, integral attachments, and retaining bolting. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exceptions to determine whether the program is adequate to manage the aging effects for which the LRA credits it. 3-33 In comparing the elements in the applicant's program to those in GALL AMP XI.M1, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent, with two exceptions. Exception

1. The LRA states the following exception to the GALL Report: NUREG-1 801 specifies the 2001 ASME Section XI B&PV Code, including the 2002 and 2003 Addenda for Subsections IWB, IWC, and IWD. The TMI-1 ISI Program Plan for the third ten-year inspection interval effective from April 20, 2001 through April 19, 2011, approved per 10 CFR 50.55a, is based on the 1995 ASME Section XI B&PV Code, including 1996 addenda. The next 120-month inspection interval for TMI-1 will incorporate the requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a twelve months before the start of the inspection interval.During the audit and review the staff noted that the ASME Section XI B&PV Code editions and addenda referenced by the applicant are different than the editions described in the GALL Report for the third ISI period. The third ISI period is within the current licensing period and therefore, the staff determined that the GALL Report guidance does not apply. The staff approved the current ISI program under the 10 CFR 50.55a process. In the LRA, the applicant stated, "The next 120-month inspection interval for TMI-1 will incorporate the requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a twelve months before the start of the inspection interval," and therefore, the staff determined that the applicant's program will be in accordance with the GALL Report during the period of extended operation.

The staff determined that there is no exception to the GALL Report AMP XI.MI. In RAI B.2.1.1-1, dated September 29, 2008, the staff requested the applicant provide additional information explaining this exception to GALL AMP XI.M1.In its response dated October 20, 2008, the applicant stated that the exception should be deleted from the LRA because the staff has approved the current ISI program under the 10 CFR 50.55a process.Based on its review, the staff finds the applicant's response to RAI B.2.1.1-1 acceptable because the applicant's ISI program will be in accordance with the recommendations of GALL AMP XI.M1 during the period of extended operation. The staff's concern described in RAI B.2.1.1-1 is resolved.Exception

2. The LRA states the following exception to the GALL Report: NUREG-1801 specifies the use of ASME Section XI B&PV Code, which includes requirements for examining Class 1 Category B-F and B-J, and Class 2 C-F-1 and C-F-2 piping components.

At TMI-1, an alternate method approved in accordance with 10 CFR 50.55a is used to determine the inspection frequency for Class 1 Category B-F and B-J, and Class 2 Category C-F-1 and C-F-2 welds in accordance with 10 CFR 50.55a(a)(3)(i) by alternatively providing an acceptable level of quality and safety. This method also addresses volumetric examination of welds less than NPS 4 inches. Other portions of the ASME Section XI ISI program outside of this scope remain unaffected. By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects," "monitoring and trending," and, "acceptance criteria" program elements.3-34 In comparing the elements in the applicant's program to those in GALL AMP XI.M1, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent, with two exceptions. Exception

1. The LRA states the following exception to the GALL Report: NUREG-1801 specifies the 2001 ASME Section XI B&PV Code, including the 2002 and 2003 Addenda for Subsections IWB, IWC, and IWD. The TMI-1 lSI Program Plan for the third ten-year inspection interval effective from April 20, 2001 through April 19, 2011, approved per 10 CFR 50.55a, is based on the 1995 ASME Section XI B&PV Code, including 1996 addenda. The next 120-month inspection interval for TMI-1 will incorporate the requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a twelve months before the start of the inspection interval.

During the audit and review the staff noted that the ASME Section XI B&PV Code editions and addenda referenced by the applicant are different than the editions described in the GALL Report for the third lSI period. The third lSI period is within the current licensing period and therefore, the staff determined that the GALL Report guidance does not apply. The staff approved the current lSI program under the 10 CFR 50.55a process. In the LRA, the applicant stated, "The next 120-month inspection interval for TMI-1 will incorporate the requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a twelve months before the start of the inspection interval," and therefore, the staff determined that the applicant's program will be in accordance with the GALL Report during the period of extended operation. The staff determined that there is no exception to the GALL Report AMP XI.M1. In RAI B.2.1.1-1, dated September 29,2008, the staff requested the applicant provide additional information explaining this exception to GALL AMP XI.M1. In its response dated October 20, 2008, the applicant stated that the exception should be deleted from the LRA because the staff has approved the current lSI program under the 10 CFR 50.55a process. Based on its review, the staff finds the applicant's response to RAI B.2.1.1-1 acceptable because the applicant's lSI program will be in accordance with the recommendations of GALL AMP XI.M1 during the period of extended operation. The staffs concern described in RAI B.2.1.1-1 is resolved. Exception

2. The LRA states the following exception to the GALL Report: NUREG-1801 specifies the use of ASME Section XI B&PV Code, which includes requirements for examining Class 1 Category B-F and B-J, and Class 2 C-F-1 and C-F-2 piping components.

At TMI-1, an alternate method approved in accordance with 10 CFR 50.55a is used to determine the inspection frequency for Class 1 Category B-F and B-J, and Class 2 Category C-F-1 and C-F-2 welds in accordance with 10 CFR 50.55a(a)(3)(i) by alternatively providing an acceptable level of quality and safety. This method also addresses volumetric examination of welds less than NPS 4 inches. Other portions of the ASME Section XI lSI program outside of this scope remain unaffected. By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects," "monitoring and trending," and, "acceptance criteria" program elements. 3-34 The staff noted that the applicant uses risk informed inservice inspection (RI-ISI) to determine inspection frequency and noted that RI-ISI and the use of specific Code Cases have been approved by the staff under the 10 CFR 50.55a process for the current ISI program and only apply to the Third ISI interval and are not applicable during the period of extended operation. The staff noted the fourth ISI interval will be performed during the period of extended operation and that the applicant's program will be submitted to the staff for the fourth ISI interval during the current license period. In RAI B.2.1.1-2 dated September 29, 2008 the staff requested the applicant provide additional information on whether they will follow ASME Code requirements and approved code cases in RG 1.147.In its response dated October 20, 2008, the applicant stated that NRC approved ASME Code inspection requirements will be followed during the fourth ISI interval which will begin April 20, 2011 and continue during the period of extended operation. Based on its review, the staff finds the applicant's response to RAI B.2.1.1-2 acceptable and also finds the exception to the GALL Report acceptable because (1) the applicant's ISI program will be in accordance with ASME Code inspection requirements endorsed by the staff in 10 CFR 55a, (2)the applicant's ISI program will be in accordance with the recommendations provided in GALL AMP XI.M1 during the period of extended operation, and (3) the intent of the GALL report is for applicants to use the version of the ASME code in effect 12 months prior to commencement of the period of extended operation. The staffs concern described in RAI B.2.1.1-2 is resolved.Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.1 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant stated that the effects of aging are effectively managed through objective evidence showing that cracking due to stress corrosion cracking, cracking due to thermal and mechanical loading, cracking due to cyclic loading, and loss of fracture toughness due to thermal aging embrittlement are being adequately managed. The applicant stated that the examples of the operating experience in the LRA provide objective evidence that the ASME Section Xl Inservice Inspection, Subsections IWB, IWC, and IWD Program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation.The staff reviewed operating experience reports and Assignment Reports. The staff noted that there is a history of degradation of the containment liner that was discovered during ISI. The staff noted that repair of the containment liner would be completed in accordance with the applicant's corrective action program prior to entering the period of extended operation. An inspection performed by the applicant of a pressurizer surge line nozzle safe-end end weld revealed a crack in the alloy 82/182 weld metal. The applicant's corrective action process provided for repair of the surge line safe-end-to-nozzle weld, and provided for augmented inspections of the surge line safe-end-to-nozzle welds during future refueling outages, and the expansion of inspection scope for similar welds. The applicant's nuclear oversight assessments have identified deficiencies in elements of the ASME Section X1 Inservice Inspection, Subsections IWB, IWC, and IWD program that were subsequently corrected through the applicant's corrective action program including inspection procedures that were not updated to the current applicable 3-35 The staff noted that the applicant uses risk informed inservice inspection (RI-ISI) to determine inspection frequency and noted that RI-ISI and the use of specific Code Cases have been approved by the staff under the 10 CFR 50.55a process for the current lSI program and only apply to the Third lSI interval and are not applicable during the period of extended operation. The staff noted the fourth lSI interval will be performed during the period of extended operation and that the applicant's program will be submitted to the staff for the fourth lSI interval during the current license period. In RAI B.2.1.1-2 dated September 29,2008 the staff requested the applicant provide additional information on whether they will follow ASME Code requirements and approved code cases in RG 1.147. In its response dated October 20, 2008, the applicant stated that NRC approved ASME Code inspection requirements will be followed during the fourth lSI interval which will begin April 20, 2011 and continue during the period of extended operation. Based on its reView, the staff finds the applicant's response to RAI B.2.1.1-2 acceptable and also finds the exception to the GALL Report acceptable because (1) the applicant's lSI program will be in accordance with ASME Code inspection requirements endorsed by the staff in 10 CFR 55a, (2) the applicant's lSI program will be in accordance with the recommendations provided in GALL AMP XI.M1 during the period of extended operation, and (3) the intent of the GALL report is for applicants to use the version of the ASME code in effect 12 months prior to commencement of the period of extended operation. The staffs concern described in RAI B.2.1.1-2 is resolved. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.1 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The applicant stated that the effects of aging are effectively managed through objective evidence showing that cracking due to stress corrosion cracking, cracking due to thermal and mechanical loading, cracking due to cyclic loading, and loss of fracture toughness due to thermal aging embrittlement are being adequately managed. The applicant stated that the examples of the operating experience in the LRA provide objective evidence that the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation. The staff reviewed operating experience reports and Assignment Reports. The staff noted that there is a history of degradation of the containment liner that was discovered during lSI. The staff noted that repair of the containment liner would be completed in accordance with the applicant's corrective action program prior to entering the period of extended operation. An inspection performed by the applicant of a pressurizer surge line nozzle safe-end end weld revealed a crack in the alloy 82/182 weld metal. The applicant's corrective action process provided for repair of the surge line safe-end-to-nozzle weld, and provided for augmented inspections of the surge line safe-end-to-nozzle welds during future refueling outages, and the expansion of inspection scope for similar welds. The applicant's nuclear oversight assessments have identified deficiencies in elements of the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program that were subsequently corrected through the applicant's corrective action program including inspection procedures that were not updated to the current applicable 3-35 ASME Code and deficiencies in documentation of repair work and inspection activities. The staff determined that these examples of operating experience provided evidence of the effectiveness of the applicant's program.The staff noted that the documentation provided by the applicant during the onsite review supported the applicant's statements regarding operating experience and the staff also confirmed that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. 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 Review. LRA Section A.2.1.1 provides the applicant's UFSAR Supplement for the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in SRP-LR, Table 3.1-2.In LRA Section A.5, Commitment No. 1, the applicant committed to the existing ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program during the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program as required by 10 CFR 54.21(d).Conclusion. On the basis of its audit and review of the applicant's ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program and the applicant's responses to the RAIs, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. In addition, the staff reviewed the exceptions and their justifications and finds that the program, with exceptions, is adequate to manage the aging effects for which the LRA credits it. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this program and concludes that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d).3.0.3.2.2 Water Chemistry Summary of Technical Information in the Application. LRA Section B.2.1.2 describes the existing Water Chemistry Program as being consistent, with an enhancement, to GALL AMP XI.M2,-"Water Chemistry Program." The applicant stated that the program provides monitoring and control of the chemical environments in the primary cycle and secondary cycle systems so that aging effects of system components are minimized. The applicant stated that the primary cycle scope of the program consists of the reactor coolant system and related auxiliary systems containing reactor coolant (borated treated water), including the primary side of the steam generators; and that the secondary cycle scope of the program consists of various secondary side systems and the secondary side of the steam generators. The applicant also stated that the program is consistent 3-36 ASME Code and deficiencies in documentation of repair work and inspection activities. The staff determined that these examples of operating experience provided evidence of the effectiveness of the applicant's program. The staff noted that the documentation provided by the applicant during the onsite review supported the applicant's statements regarding operating experience and the staff also confirmed that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A1.2.3.1 O. The staff finds this program element acceptable. UFSAR Supplement Review. LRA Section A2.1.1 provides the applicant's UFSAR Supplement for the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in SRP-LR, Table 3.1-2. In LRA Section A5, Commitment No.1, the applicant committed to the existing ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWO Program during the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWO Program as required by 10 CFR 54.21(d}. Conclusion. On the basis of its audit and review of the applicant's ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWO Program and the applicant's responses to the RAls, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. In addition, the staff reviewed the exceptions and their justifications and finds that the program, with exceptions, is adequate to manage the aging effects for which the LRA credits it. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s} will be maintained consistent with the CLB for the period of extended operation as required by 10 CFR 54.21 (a}(3). The staff also reviewed the UFSAR Supplement for this program and concludes that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d}. 3.0.3.2.2 Water Chemistry Summary of Technical Information in the Application. LRA Section B.2.1.2 describes the existing Water Chemistry Program as being consistent, with an enhancement, to GALL AMP XI.M2, Water Chemistry Program." The applicant l5tated that the program provides monitoring and control of the chemical environments in the primary cycle and secondary cycle systems so that aging effects of system components are minimized. The applicant stated that the primary cycle scope of the program consists of the reactor coolant system and related auxiliary systems containing reactor coolant (borated treated water), including the primary side of the steam generators; and that the secondary cycle scope of the program consists of various secondary side systems and the secondary side of the steam generators. The applicant also stated that the program is consistent 3-36 with Electric Power Research Institute's (EPRI), "Pressurized Water Reactor (PWR) Primary Chemistry Guidelines," Revision 5, and with plant technical specification limits for fluorides, chlorides, and dissolved oxygen. The applicant also stated that the program will be enhanced to become consistent with EPRI, "PWR Secondary Water Chemistry Guidelines," Revision 6, and that the enhancement will incorporate continuous monitoring of sodium in steam generator blowdown.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the enhancement to determine whether the AMP, with the enhancement, is adequate to manage the aging effects for which the LRA credits it.In comparing the elements in the applicant's program to those in the GALL Report AMP XI.M2, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. The staff did, although, identify issues with the chemistry parameter action limits and diagnostic parameter sampling frequency. In RAI B.2.1.2-1, dated September 29, 2008, the staff requested that the applicant provide additional information concerning this issue.In RAI B.2.1.2-1, the staff noted following differences between the plant's implementing procedures for its Water Chemistry Program and recommendations in EPRI's PWR Primary Coolant Chemistry Guidelines, Revision 5:(a) There is no dissolved oxygen action limit for AL2 recommended by EPRI, but plant procedure uses a value of greater than 100 parts per billion (ppb).(b) The dissolved oxygen action limit for AL3 recommended by EPRI is greater than 100 ppb, but plant procedure uses a value of greater than 1000 ppb.(c) The sampling frequency for conductivity recommended by EPRI is once per day, but plant procedure uses a value of five per week.(d) The sampling frequency for pH recommended by EPRI is once per day, but plant procedure uses a value of five per week.(e) The sampling frequency for boron recommended by EPRI is once per day, but plant procedure uses a value of two per week.The staff requested that the applicant explain why these differences are not considered to be exceptions to GALL AMP XI.M2, which states that a PWR applicant's primary water chemistry program should be based on EPRI's PWR Primary Water Chemistry Guidelines, Revision 3 or later. The staff also asked the applicant to provide a technical justification as to why the differences between the applicant's program and the recommendations in the EPRI guidelines are acceptable to provide adequate protection for components affected by primary water chemistry. In its response to the RAI dated October 20, 2008, the applicant stated that Revision 6 of EPRI'sPWR Primary Water Chemistry Guidelines, dated December 2007, has been implemented and that there was a change in the dissolved oxygen concentration action limits between Revisions 5 and 6 of the EPRI guideline. The applicant stated that the dissolved oxygen concentration action limits in Revision 6 of the guidelines are identical to the action limits in the TMI-1 chemistry procedures. The applicant also stated that Revision 6 of the ERPI guidelines no longer require 3-37 with Electric Power Research Institute's (EPRI), "Pressurized Water Reactor (PWR) Primary Chemistry Guidelines," Revision 5, and with plant technical specification limits for fluorides, chlorides, and dissolved oxygen. The applicant also stated that the program will be enhanced to become consistent with EPRI, "PWR Secondary Water Chemistry Guidelines," Revision 6, and that the enhancement will incorporate continuous monitoring of sodium in steam generator blowdown. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the enhancement to determine whether the AMP, with the enhancement, is adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in the GALL Report AMP XI.M2, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. The staff did, although, identify issues with the chemistry parameter action limits and diagnostic parameter sampling frequency. In RAI B.2.1.2-1, dated September 29, 2008, the staff requested that the applicant provide additional information concerning this issue. In RAI B.2.1.2-1, the staff noted following differences between the plant's implementing procedures for its Water Chemistry Program and recommendations in EPRl's PWR Primary Coolant Chemistry Guidelines, Revision 5: (a) There is no dissolved oxygen action limit for AL2 recommended by EPRI, but plant procedure uses a value of greater than 100 parts per billion (ppb). (b) The dissolved oxygen action limit for AL3 recommended by EPRI is greater than 100 ppb, but plant procedure uses a value of greater than 1000 ppb. (c) The sampling frequency for conductivity recommended by EPRI is once per day, but plant procedure uses a value of five per week. (d) The sampling frequency for pH recommended by EPRI is once per day, but plant procedure uses a value of five per week. (e) The sampling frequency for boron recommended by EPRI is once per day, but plant procedure uses a value of two per week. The staff requested that the applicant explain why these differences are not considered to be exceptions to GALL AMP XI.M2, which states that a PWR applicant's primary water chemistry program *should be based on EPRl's PWR Primary Water Chemistry Guidelines, Revision 3 or later. The staff also asked the applicant to provide a technical justification as to why the differences between the applicant's program and the recommendations in the EPRI guidelines are acceptable to provide adequate protection for components affected by primary water chemistry. In its response to the RAI dated October 20,2008, the applicant stated that Revision 6 of EPRI's PWR Primary Water Chemistry Guidelines, dated December 2007, has been implemented and that there was a change in the dissolved oxygen concentration action limits between Revisions 5 and 6 of the EPRI guideline. The applicant stated that the dissolved oxygen concentration action limits in Revision 6 of the guidelines are identical to the action limits in the TMI-1 chemistry procedures. The applicant also stated that Revision 6 of the ERPI guidelines no longer require 3-37 sampling for pH. The applicant also stated that the EPRI guidelines allow measurement of conductivity and boron concentration to be based on individual plant needs because they are diagnostic parameters, rather than control parameters, and that conductivity measurements and boron concentration measurements of five times per week and two times per week, respectively, are adequate based on TMI-I's TS and operating experience. The staff reviewed the applicant's response to RAI B.2.1.2-1 together with EPRI's PWR Primary Water Chemistry Guidelines, Revision 6, dated December 2007 and noted that the applicant's procedural limits on dissolved oxygen content in reactor coolant are consistent with the recommendations of EPRI's PWR Primary Water Chemistry Guidelines, Revision 6. The staff alsonoted that the applicant implemented the change to use EPRI's PWR Primary Water Chemistry Guidelines, Revision 6, after the LRA submittal date of January 08, 2008. The staff noted that the change in recommended action limits between Revision 5 and Revision 6 of the EPRI guidelines provides an additional 24 hour window for plant operations to restore dissolved oxygen content to acceptable levels if dissolved oxygen concentration is greater than 100 ppb, but less than 1000 ppb. The staff finds the additional 24 hour operating window to be acceptable because it provides additional flexibility to implement corrective actions without allowing an elevated dissolved oxygen concentration to continue for a substantially longer time than was allowed under the previous EPRI guidelines. The staff finds the applicant's response with regard to dissolved oxygen concentration to be acceptable because it is consistent with the most recent EPRI PWR Primary Water Chemistry Guidelines and is consistent with the recommendation in the GALL Report that a PWR primary water chemistry program be based on Revision 3 or later editions ofEPRI PWR Water Chemistry Guidelines. The staff reviewed the applicant's response with regard to sampling frequency for the diagnostic parameters, primary water conductivity, pH, and boron concentration. The staff noted that Revision 6 of the EPRI guidelines has deleted the previous recommendation for sampling of pH.The staff also noted that the EPRI guidelines describe diagnostic parameters as assisting interpretation of primary coolant chemistry variations, rather than requiring strict control due to material integrity issues, and the guidelines classify diagnostic parameter measurement frequencies as suggestions that can be modified based on plant-specific operating experience and technical specification requirements. Based on changes in the EPRI guidelines that deleted recommendations for pH sampling and provisions that allow deviations from suggested sampling frequencies for diagnostic parameters, the staff determined that the applicant's procedural requirements related to sampling frequencies for pH, conductivity, and boron concentration are consistent with EPRI's most recent PWR Primary Water Chemistry Guidelines and are, therefore, consistent with recommendations in the GALL Report. On this basis, the staff finds the applicant's response with regard to diagnostic parameters to be acceptable. The staffs concerns described in RAI B.2.1.2-1 are resolved.Enhancement. LRA Section B.2.1.2 states the following enhancement to the GALL Report: The TMI-1 Water Chemistry Program will be enhanced to include the continuous monitoring of steam generator blowdown for sodium during startup and hot standby conditions as required by EPRI 1008224, "PWR Secondary Water Chemistry Guidelines," Revision 6. This enhancement will be implemented after replacement of the existing once-through steam generators and prior to the period of extended operation for TMI-1.By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program," and, "monitoring and trending" program elements.3-38 sampling for pH. The applicant also stated that the EPRI guidelines allow measurement of conductivity and boron concentration to be based on individual plant needs because they are diagnostic parameters, rather than control parameters, and that conductivity measurements and boron concentration measurements of five times per week and two times per week, respectively, are adequate based on TMI-1 's TS and operating experience. The staff reviewed the applicant's response to RAI B.2.1.2-1 together with EPRl's PWR Primary Water Chemistry Guidelines, Revision 6, dated December 2007 and noted that the applicant's procedural limits on dissolved oxygen content in reactor coolant are consistent with the recommendations of EPRl's PWR Primary Water Chemistry Guidelines, Revision 6. The staff also noted that the applicant implemented the change to use EPRI's PWR Primary Water Chemistry Guidelines, Revision 6, after the LRA submittal date of January 08, 2008. The staff noted that the change in recommended action limits between Revision 5 and Revision 6 of the EPRI guidelines provides an additional 24 hour window for plant operations to restore dissolved oxygen content to acceptable levels if dissolved oxygen concentration is greater than 100 ppb, but less than 1000 ppb. The staff finds the additional 24 hour operating window to be acceptable because it provides additional flexibility to implement corrective actions without allowing an elevated dissolved oxygen concentration to continue for a substantially longer time than was allowed under the previous EPRI guidelines. The staff finds the applicant's response with regard to dissolved oxygen concentration to be acceptable because it is consistent with the most recent EPRI PWR Primary Water Chemistry Guidelines and is consistent with the recommendation in the GALL Report that a PWR primary water chemistry program be based on Revision 3 or later editions of EPRI PWR Water Chemistry Guidelines. The staff reviewed the applicant's response with regard to sampling frequency for the diagnostiC parameters, primary water conductivity, pH, and boron concentration. The staff noted that Revision 6 of the EPRI guidelines has deleted the previous recommendation for sampling of pH. The staff also noted that the EPRI guidelines describe diagnostiC parameters as assisting interpretation of primary coolant chemistry variations, rather than requiring strict control due to material integrity issues, and the guidelines classify diagnostic parameter measurement frequencies as suggestions that can be modified based on plant-specific operating experience and technical specification requirements. Based on changes in the EPRI guidelines that deleted recommendations for pH sampling and provisions that allow deviations from suggested sampling frequencies for diagnostic parameters, the staff determined that the applicant's procedural requirements related to sampling frequencies for pH, conductivity, and boron concentration are consistent with EPRl's most recent PWR Primary Water Chemistry Guidelines and are, therefore, consistent with recommendations in the GALL Report. 01) this. basis, the staff finds the applicant's response with regard to diagnostic parameters to be acceptable. The staffs concerns described in RAI B.2.1.2-1 are resolved. Enhancement. LRA Section B.2.1.2 states the following enhancement to the GALL Report: The TMI-1 Water Chemistry Program will be enhanced to include the continuous monitoring of steam generator blowdown for sodium during startup and hot standby conditions as required by EPR11008224, "PWR Secondary Water Chemistry Guidelines," Revision 6. This enhancement will be implemented after replacement of the existing through steam generators and prior to the period of extended operation for TMI-1. By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program," and, "monitoring and trending" program elements. 3-38 In the applicant's program basis document for the Water Chemistry Program, the applicant stated that the EPRI guidance is not currently being followed because of existing plant design and hydraulic conditions which prevent the collection of steam generator blowdown samples while simultaneously operating steam generator blowdown. The applicant stated that in lieu of continuously monitoring steam generator blowdown for sodium, steam generator feedwater is continuously monitored, and steam generator grab samples are collected and analyzed forsodium on a minimum frequency of once per four hours. The applicant stated that these practices will continue until the once-through steam generators are replaced. The applicant stated that the replacement steam generators will support simultaneous sodium monitoring and blowdown as recommended in EPRI's PWR Secondary Water Chemistry Guidelines, Revision 6.In LRA Section A.5, Commitment 2, the applicant committed to enhance the Water Chemistry Program to incorporate continuous monitoring of sodium in steam generator blowdown prior to the period of extended operation. Based on its review, the staff finds the enhancement acceptable because it will bring theapplicant's Water Chemistry Program into conformance with EPRI's PWR Secondary WaterChemistry Guidelines that are the basis for the GALL Report's Water Chemistry Program and the because applicant committed to implement the enhancement prior to the period of extended operation.' Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.2 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant stated that the Water Chemistry Program is a preventative program that assures contaminants are maintained below applicable limits to prevent the aging of plant piping and components and that potential aging effects of cracking, denting, loss of material, reduction of heat transfer, and reduction of neutron-absorbing capacity are being adequately managed. The applicant provided three examples of site-specific operating experience to demonstrate effectiveness of the program as follows: (1) The applicant stated that in June 2002, feedwater sodium level exceeding Action Level 1 values of ! ppb were identified. The applicant stated this was the only occurrence of a chemistry action level being exceeded in the preceding five years. The applicant stated that an investigation identified the cause of the sodium increase as a condenser tube leak, and prompt corrective actions led to restoring the feedwater sodium value to below 1 ppb within one day of discovery. (2) The applicant stated that in March 2004, a focused area self-assessment of the Water Chemistry Program was performed. The applicant stated that the self-assessment confirmed strengths and identified deficiencies in the program, and that programmatic deficiencies were evaluated and corrective actions taken, including procedure revisions to incorporate needed changes.(3) The applicant stated that in May 2006, routine water chemistry monitoring identified chloride concentration in the reactor coolant system that was higher than administrative 3-39 In the applicant's program basis document for the Water Chemistry Program, the applicant stated that the EPRI guidance is not currently being followed because of existing plant design and hydraulic conditions which prevent the collection of steam generator bJowdown samples while simultaneously operating steam generator blowdown. The applicant stated that in lieu of continuously monitoring steam generator blowdown for sodium, steam generator feedwater is continuously monitored, and steam generator grab samples are collected and analyzed for sodium on a minimum frequency of once per four hours. The applicant stated that these practices will continue until the once-through steam generators are replaced. The applicant stated that the replacement steam generators will support simultaneous sodium monitoring and blowdown as recommended in EPRl's PWR Secondary Water Chemistry Guidelines, Revision 6. In LRA Section A.5, Commitment 2, the applicant committed to enhance the Water Chemistry Program to incorporate continuous monitoring of sodium in steam generator blowdown prior to the period of extended operation. . Based on its review, the staff finds the enhancement acceptable because it will bring the applicant's Water Chemistry Program into conformance with EPRl's PWR Secondary Water Chemistry Guidelines that are the basis for the GALL Report's Water Chemistry Program and the because applicant committed to implement the enhancement prior to the period of extended operation. '. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.2 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The applicant stated that the Water Chemistry Program is a preventative program that assures contaminants are maintained below applicable limits to prevent the aging of plant piping and components and that po"tential aging effects of cracking, denting, loss of material, reduction of heat transfer, and reduction capacity are being adequately managed. the applicant provided three examples of site-specific operating experience to demonstrate effectiveness of the program as follows: (1) The applicant stated that in June 2002, feedwater sodium level exceeding Action Level 1 values of 1 ppb were identified. The applicant stated this was the only occurrence of a chemistry action level being exceeded in the preceding five years. The applicant stated that an investigation identified the cause of the sodium increase as a condenser tube leak, and prompt corrective actions led to restoring the feedwater sodium value to below 1 ppb within one day of discovery. (2) The applicant stated that in March 2004, a focused area self-assessment of the Water Chemistry Program was performed. The applicant stated that the self-assessment confirmed strengths and identified deficiencies in the program, and that programmatic deficiencies were evaluated and corrective actions taken, including procedure revisions to incorporate needed changes. (3) The applicant stated that in May 2006, routine water chemistry monitoring identified chloride concentration in the reactor coolant system that was higher than administrative 3-39 goals. The applicant further stated that the cause of the higher-than-goal chloride levels was identified, and corrective actions were identified and implemented to reduce chloride levels to below the administrative goals.In addition to these examples, the staff reviewed the applicant's operating experience discussion provided in the applicant's program basis document binder for the Water Chemistry Program. The staff reviewed additional selected corrective ARs related to the Water Chemistry Program and interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. Based on this review, the staff finds (1) that the operating experience for this program demonstrates that the applicant's Water Chemistry Program is achieving its objective of mitigating aging effects of cracking, denting, loss of material, reductions of heat transfer and reduction of neutron-absorbing capacity for materials exposed to primary cycle and secondary cycle treated water; and (2) that the applicant is taking appropriate corrective actions through implementation of this program.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 Review. In LRA Section A.2.1.2, the applicant provided the UFSAR Supplement for the Water Chemistry Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff s recommended UFSARSupplement guidance for this type of program as found in SRP-LR Table 3.1-2.In LRA Section A.5, Commitment No. 2, the applicant committed to ongoing implementation of the Water Chemistry Program for aging management of applicable components during the period of extended operation and also committed to the program enhancement regarding continuous monitoring of sodium in steam generator blowdown prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the WaterChemistry Program in the UFSAR Supplement as required by 10 CFR 54.21(d).Conclusion. On the basis of its review of the applicant's Water Chemistry program and the applicant's response to the staffs RAI, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff also reviewed the enhancement and confirms that its implementation through Commitment No. 2 prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d).3.0.3.2.3 Reactor Head Closure Studs Summary of Technical Information in the Application. LRA Section B.2.1.3 describes the existing Reactor Head Closure Studs Program as being consistent, with exceptions, to GALL AMP XI.M3,"Reactor Head Closure Studs." 3-40 goals. The applicant further stated that the cause of the higher-than-goal chloride levels was identified, and corrective actions were identified and implemented to reduce chloride levels to below the administrative goals. In addition to these examples, the staff reviewed the applicant's operating experience discussion provided in the applicant's program basis document binder for the Water Chemistry Program. The staff reviewed additional selected corrective ARs related to the Water Chemistry Program and interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. . Based on this review, the staff finds (1) that the operating experience for this program demonstrates that the applicant's Water Chemistry Program is achieving its objective of mitigating aging effects of cracking, denting, loss of material, reductions of heat transfer and reduction of neutron-absorbing capacity for materials exposed to primary cycle and secondary cycle treated water; and (2) that the applicant is taking appropriate corrective actions through implementation of this program. . The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1 O. The staff finds this program element acceptable. UFSAR Supplement Review. In LRA Section A.2.1.2, the applicant provided the UFSAR Supplement for the Water Chemistry Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staffs recommended UFSAR Supplement guidance for this type of program as found in SRP-LR Table 3.1-2. In LRA Section A.5, Commitment No.2, the applicant committed to ongoing implementation of the Water Chemistry Program for aging management of applicable components during the period of extended operation and also committed to the program enhancement regarding continuous monitoring of sodium in steam generator blowdown prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Water Chemistry Program in the UFSAR Supplement as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's Water Chemistry program and the applicant's response to the staffs RAI, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff also reviewed the enhancement and confirms that its implementation through Commitment No.2 prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d). 3.0.3.2.3 Reactor Head Closure Studs Summary of Technical Information in the Application. LRA Section 8.2.1.3 describes the existing Reactor Head Closure Studs Program as being consistent, with exceptions, to GALL AMP XI.M3, "Reactor Head Closure Studs." 3-40 The applicant stated that the program manages the effects of aging for reactor head closure studs and stud components constructed from materials with a maximum tensile strength limited to less than 170 ksi through the implementation of plant procedures following the examination and inspection requirements of ASME Section XI Table, IWB-2500-1, and the guidance provided in NRC RG 1.65, "Materials and Inspection for Reactor Vessel Closure Studs." The applicant further stated that aging effects requiring management include cracking due to stress corrosion cracking, and loss of material due to wear, general, pitting and crevice corrosion. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exceptions to determine whether the AMP, with the exceptions is adequate to manage the aging effects for which the LRA credits it.In comparing the elements in the applicant's program to those in GALL AMP XI.M3, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent, but several issues were identified with the "scope of program,""detection of aging effects," and "preventive actions" program elements.The staff determined that a possible exception to the "scope of program" and "detection of aging effects" program elements exists regarding the applicant's detection of coolant leakage. The staff determined that the applicant did not explicitly identify the detection of coolant leakage from reactor vessel closure stud bolting in its on-site basis documents. In RAI B.2.1.3-1, dated October 7, 2008, the staff requested that the applicant provide additional information on the applicant'sleak detection process.In its response to the RAI dated October 30, 2008, the applicant stated that the AMP will include techniques to detect coolant leakage from reactor vessel closure stud bolting. The applicant further clarified the issue and stated that the following statement should have been included in its basis document for sections 3.1 .a "scope of the program," 3.4.a "detection of aging effects," and 3.5 "monitoring and trending,": During system pressure tests, VT-2 visual techniques are employed to monitor for coolant leakage.Based on its review, the staff finds that this clarification meets the recommendations of GALL AMP XI.M3, and is acceptable. The staff's concern in RAI B.2.1.3-1 is resolved.The staff determined that a possible exception to the "preventive actions" program element exists regarding the application of a stable lubricant. The staff determined that the applicant's on-site basis document identifies Dow Corning G-N metal spray as a lubricant used during the installation process for reactor head closure studs. Upon closer review of the specification sheet for this lubricant, the staff discovered that Dow Corning G-N metal spray is composed of 14%Molybdenum Disulfide. NRC RG 1.65 specifies the use of lubricants which are stable and compatible with the bolting and vessel materials and the surrounding environment. Molybdenum Disulfide is evaluated in EPRI-NP-5769, and NUREG/CR-3766, and found to be a compound that is discouraged from use because of its susceptibility to promote stress corrosion cracking. In RAI B.2.1.3-3, dated October 7, 2008, the staff requested that the applicant provide additional information concerning the use of this lubricant. In its response to the RAI dated October 30, 2008, the applicant stated that current plant procedures specify the use of Dow Corning G-N Metal spray as a lubricant for the reactor head closure studs. The applicant further stated that the program will be enhanced to satisfy the recommendations of GALL AMP XI.M3. The applicant stated that the enhancement applies to the"scope of program" and "preventive actions" program elements as follows: 3-41 The applicant stated that the program manages the effects of aging for reactor head closure studs and stud components constructed from materials with a maximum tensile strength limited to less than 170 ksi through the implementation of plant procedures following the examination and inspection requirements of ASME Section XI Table, IWB-2500-1, and the guidance provided in NRC RG 1.65, "Materials and Inspection for Reactor Vessel Closure Studs." The applicant further stated that aging effects requiring management include cracking due to stress corrosion cracking, and loss of material due to wear, general, pitting and crevice corrosion. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exceptions to determine whether the AMP, with the exceptions is adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in GALL AMP XI.M3, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent, but several issues were identified with the "scope of program," "detection of aging effects," and "preventive actions" program elements. The staff determined that a possible exception to the "scope of program" and "detection of aging effects" program elements exists regarding the applicant's detection of coolant leakage. The staff determined that the applicant did not explicitly identify the detection of coolant leakage from reactor vessel closure stud bolting in its on-site basis documents. In RAI B.2.1.3-1, dated October 7, 2008, the staff requested that the applicant provide additional information on the applicant's leak detection process. In its response to the RAI dated October 30, 2008, the applicant stated that the AMP will include , techniques to detect coolant leakage from reactor vessel closure stud bolting. The applicant further clarified the issue and stated that the following statement should have been included in its basis document for sections 3.1.a "scope of the program," 3A.a "detection of aging effects," and 3.5 "monitoring and trending,": During system pressure tests, VT -2 visual techniques are employed to monitor for coolant leakage. Based on its review, the staff finds that this clarification meets the recommendations of GALL AMP XI.M3, and is acceptable. The staff's concern in RAI B.2.1.3-1 is resolved. The staff determined that a possible exception to the "preventive actions" program element exists regarding the application of a stable lubricant. The staff determined that the applicant's on-site basis document identifies Dow Corning G-N metal spray as a lubricant used during the installation process for reactor head closure studs. Upon closer review of the specification sheet for this lubricant, the staff discovered that Dow Corning G-N metal spray is composed of 14% Molybdenum Disulfide. NRC RG 1.65 specifies the use of lubricants which are stable and compatible with the bolting and vessel materials and the surrounding environment. Molybdenum Disulfide is evaluated in EPRI-NP-5769, and NUREG/CR-3766, and found to be a compound that is discouraged from use because of its susceptibility to promote stress corrosion cracking. In RAI B.2.1.3-3, dated October 7, 2008, the staff requested that the applicant provide additional information concerning the use of this lubricant. In its response to the RAI dated October 30, 2008, the applicant stated that current plant procedures specify the use of Dow Corning G-N Metal spray as a lubricant for the reactor head closure studs. The applicant further stated that the program will be enhanced to satisfy the recommendations of GALL AMP XI.M3. The applicant stated that the enhancement applies to the "scope of program" and "preventive actions" program elements as follows: 3-41 The Reactor Head Closure Studs program will be enhanced to select an alternate stable lubricant that is compatible with the fastener material and the environment. This enhancement will be implemented prior to the period of extended operation. The staff reviewed the applicant's enhancement and confirmed that no indication of deficiencies with reactor head closure studs or stud components was found in the past inspection results. The staff also reviewed EPRI-5769, Volume 1, Section 11 and found that it specifically identifies lubricants containing molybdenum disulfides as a common factor in several SCC related failures.The applicant's enhancement directly addresses this issue, as it commits to include a specific precaution against the use of compounds containing sulfur (sulfide), including molybdenum disulfide (MoS 2), as a lubricant for bolting.Based on its review, the staff finds the applicant's response to RAI B.2.1.3-2 acceptable because the AMP, with the enhancement, will be consistent with the recommendations of GALL AMP XI.M3. The staffs concern in RAI B.2.1.3-2 is resolved.Exception

1. The LRA states an exception to the GALL Report as follows: NUREG-1801, XI.M3, specifies the 2001 ASME Section Xl B&PV Code, including the 2002 and 2003 Addenda. The current TMI-1 ISI Program Plan for the third ten-year inspection interval effective from April 20, 2001 through April 19, 2011, approved per 10 CFR 50.55a, is based on the 1995 ASME Section Xl B&PV Code, including 1996 addenda. The next 120-month inspection interval for TMI-1 will incorporate the requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a twelve months before the start of the inspection interval.The staff reviewed the 1995 edition of the ASME Code Section Xl including 1996 addenda, and found that this was the ASME Code Section Xl edition in effect for the 3 rd 10-Year ISI Interval for TMI Unit 1. The staff noted that the applicant is scheduled to enter its 4 th 10-Year ISI Interval on April 20, 2011. Since the 1995 edition of the ASME Code Section Xl including 1996 addenda was previously approved per 10 CFR 50.55a, the staff finds that the exception noted by the applicant is incorrectly designated as such. In RAI B.2.1.3-2, dated October 7, 2008, the staff requested that the applicant provide additional information clarifying whether this issue is an exception.

In its response to the RAI dated October 30, 2008, the applicant provided its agreement with the staff's position. The applicant stated that a formal exception to the ASME code version listed in the GALL AMP XI.M3 is not necessary, and subsequently removed the exception from the LRA.The staff determined that the use of the 1998 Edition of the ASME Code Section XI, inclusive of the 2000 Addenda, is consistent with the program description statement in GALL AMP XI.M3 because the Statement of Consideration (SOC) of 10 CFR Part 54 clarifies that acceptable editions of the ASME Code Section Xl are those acceptable endorsed editions up to the most recently endorsed edition discussed in 10 CFR 50.55a. The staff confirmed that the SOC of 10 CFR Part 54 does include this clarification, and that based on this clarification, use of the 1998 Edition of the ASME Code Section XI, inclusive of the 2000 Addenda, is consistent with the program description of GALL AMP XI.M3.Based on its review, the staff finds the applicant's response to RAI B.2.1.3-2 acceptable because crediting the 1998 edition of the ASME Code Section Xl, inclusive of the 2000 Addenda, is consistent with GALL AMP XI.M3. The staff's concern in RAI B.2.1.3-2 is resolved.3-42 The Reactor Head Closure Studs program will be enhanced to select an alternate stable lubricant that is compatible with the fastener material and the environment. This enhancement will be implemented prior to the period of extended operation. The staff reviewed the applicant's enhancement and confirmed that no indication of deficiencies with reactor head closure studs or stud components was found in the past inspection results. The staff also reviewed EPRI-5769, Volume 1, Section 11 and found that it specifically identifies lubricants containing molybdenum disulfides as a common factor in several SCC related failures. The applicant's enhancement directly addresses this issue, as it commits to include a specific precaution against the use of compounds containing sulfur (sulfide), including molybdenum disulfide (MoS 2), as a lubricant for bolting. 8ased on its review, the staff finds the applicant's response to RAI 8.2.1.3-2 acceptable because the AMP, with the enhancement, will be consistent with the recommendations of GALL AMP XLM3. The staff's concern in RAI B.2.1.3-2 is resolved. Exception

1. The LRA states an exception to the GALL Report as follows: NUREG-1801, XLM3, specifies the 2001 ASME Section XIB&PV Code, including the 2002 and 2003 Addenda. The current TMI-1 lSI Program Plan for the third ten-year inspection interval effective from April 20, 2001 through April 19, 2011, approved per 10 CFR 50.55a, is based on the 1995 ASME Section XI B&PV Code, including 1996 addenda. The next 120-month inspection interval for TMI-1 will incorporate the requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a twelve months before the start of the inspection interval.

The staff reviewed the 1995 edition of the ASME Code Section XI including 1996 addenda, and . found that this was the ASME Code Section XI edition in effect for the 3 rd 10-Year lSI Interval for TMI Unit 1. The staff noted that the applicant is scheduled to enter its 4th 10-Year lSI Interval on April 20, 2011. Since the 1995 edition of the ASME Code Section XI including 1996 addenda was previously approved per 10 CFR 50.55a, the staff finds that the exception noted by the applicant is incorrectly designated as such. In RAI B.2.1.3-2, dated October 7,2008, the staff requested that the applicant provide additional information clarifying whether this issue is an exception. In its response to the RAI dated October 30, 2008, the applicant provided its agreement with the staff's position. The applicant stated that a formal exception to the ASME code version listed in the GALL AMP XI.M3 is not necessary, and subsequently removed the exception from the LRA. The staff determined that the use of the 1998 Edition of the ASME Code Section XI, inclusive of the 2000 Addenda, is consistent with the program description statement in GALL AMP XLM3 because the Statement of Consideration (SOC) of 10 CFR Part 54 clarifies that acceptable editions of the ASME Code Section XI are those acceptable endorsed editions up to the most recently endorsed edition discussed in 10 CFR 50.55a. The staff confirmed that the SOC of 10 CFR Part 54 does include this clarification, and that based on this clarification, use of the 1998 . Edition of the ASME Code Section XI; inclusive of the 2000 Addenda, is consistent with the program description of GALL AMP XI.M3. Based on its review, the staff finds the applicant's response to RAI B.2.1.3-2 acceptable because crediting the 1998 edition of the ASME Code Section XI, inclusive of the 2000 Addenda, is consistent with GALL AMP XI.M3. The staff's concern in RAI B.2.1.3-2 is resolved. 3-42 Exception

2. The LRA states an exception to the GALL Report as follows: NUREG-1801, X1.M3, specifies that surface examination uses magnetic particle, liquid penetration, or eddy current examinations to indicate the presence of surface discontinuities and flaws in the reactor head closure studs. The current TMI-1 ISI program for the third interval does not require surface examination.

The next 120-month inspectioninterval for TMI-1 will incorporate the requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a twelve months before the start of the inspection interval.The staff reviewed the 1995 edition of the ASME, Section XI, B&PV Code, including the 1996 addenda and found that the requirements of this edition have been met. The applicant stated that the next 10-year inspection interval will incorporate the code requirements specified in 10 CFR 50.55a twelve months before the start of the inspection interval. The staff noted that this examination requirement was not required as part of the 1995 edition of the code. The staff also noted that since the 1995 edition of the code including the 1996 addenda was previouslyapproved per 10 CFR 50.55a, that the exception noted by the applicant is incorrectly designated as such. In RAI B.2.1.3-2 dated October 7, 2008, the staff requested that the applicant provide additional information clarifying whether this issue is an exception. In its response to the RAI dated October 30, 2008, the applicant provided its agreement with the staff's position. The applicant stated that a formal exception to the ASME code version listed in the GALL AMP XI.M3 is not necessary, and subsequently removed the exception from the LRA.The staff determined that the use of the 1998 Edition of the ASME Code Section XI, inclusive of the 2000 Addenda, is consistent with the program description statement in GALL AMP XI.M3 because the SOC of 10 CFR Part 54 clarifies that acceptable editions of the ASME Code Section Xl are those acceptable endorsed editions up to the most recently endorsed edition discussed in 10 CFR 50.55a. The staff confirmed that the SOC of 10 CFR Part 54 does include this clarification, and that based on this clarification, use of the 1998 Edition of the ASME Code Section Xl, inclusive of the 2000 Addenda, is consistent with the program description of GALL AMP XI.M3.Based on its review, the staff finds the applicant's response to RAI B.2.1.3-2 acceptable because crediting the 1998 edition of the ASME Code Section XI, inclusive of the 2000 Addenda, is consistent with GALL AMP XI.M3. The staffs concern in RAI B.2.1.3-2 is resolved.Operatingq Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.3 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmedthat the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant stated that the program is being effectively implemented to meet regulatory, process, and procedure requirements, including periodic reviews. The staff reviewed the operating experience reports to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The reports indicated that during recent refueling outages in 2003 and 2005, UT, MT, and VT-1 exams were conducted which found no undesirable indications. The applicant further stated that no undesirable indications have ever been recorded on the reactor head closure studs, but that industry operating experience is utilized 3-43 Exception

2. The LRA states an exception to the GALL Report as follows: NUREG-1801, X1.M3, specifies that surface examination uses magnetic particle, liquid penetration, or eddy current examinations to indicate the presence of surface discontinuities and flaws in the reactor head closure studs. The current TMI-1 lSI program for the third interval does not require surface examination.

The next 120-month inspection interval for TMI-1 will incorporate the requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a twelve months before the start of the inspection interval. The staff reviewed the 1995 edition of the ASME, Section XI, B&PV Code, including the 1996 addenda and found that the requirements of this edition have been met. The applicant stated that the next 1 O-year inspection interval will incorporate the code requirements specified in 10 CFR 50.55a twelve months before the start of the inspection interval. The staff noted that this examination requirement was not required as part of the 1995 edition of the code. The staff also noted that since the 1995 edition of the code including the 1996 addenda was' previously approved per 10 CFR 50.55a, that the exception noted by the applicant is incorrectly designated as such. In RAI B.2.1.3-2 dated October 7, 2008, the staff* requested that the applicant provide additional information clarifying whether this issue is an exception. In its response to the RAI dated October 30, 2008, the applicant provided its agreement with the staff's position. The applicant stated that a formal exception to the ASME code version listed in the GALL AMP XI.M3 is not necessary, and subseque':ltly removed the exception from the LRA. The staff determined that the use of the 1998 Edition of the ASME Code Section XI, inclusive of the 2000 Addenda, is consistent with the program description statement in GALL AMP XI.M3 because the SOC of 10 CFR Part 54 clarifies that acceptable editions of the ASME Code Section XI are those acceptable endorsed editions up to the most recently endorsed edition discussed in 10 CFR 50.55a. The staff confirmed that the SOC of10 CFR Part 54 does include this clarification, and that based on this clarification, use of the 1998 Edition of the ASME Code Section XI, inclusive of the 2000 Addenda, is consistent with the program description of GALL AMP XI.M3. Based on its review, the staff finds the applicant's response to RAI B.2.1.3-2 acceptable because crediting the 1998 edition of the ASME Code Section XI, inclusive of the 2000 Addenda, is consistent with GALL AMP XI.M3. The staff's concern in RAI B.2.1.3-2 is resolved. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.3 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The applicant stated that the program is being effectively implemented to meet regulatory, process, and procedure requirements, including periodiC reviews. The staff reviewed the operating experience reports to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The reports indicated that during recent refueling outages in 2003 and 2005, UT, MT, and VT-1 exams were conducted which found no undesirable indications. The applicant further stated that no undesirable indications have ever been recorded on the reactor head closure studs, but that industry operating experience is utilized 3-43'* to supplement its own AMP by completing industry recommendations and evaluations to address issues that have occurred at other plants. Additionally, the staff reviewed several industry operating experiences along with the resulting response taken by the applicant to apply the lessons learned to its own program and found the responses to be satisfactory. 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. LRA section A.2.1.3 provides the applicant's UFSAR Supplement for the Reactor Head Closure Studs Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staffs recommended UFSAR Supplement guidance found in the SRP-LR.In LRA Section A.5, Commitment No. 3, the applicant committed to credit the program for aging management during the period of extended operation. In its letter dated October 30, 2008, the applicant revised Commitment No. 3 to incorporate the enhancement concerning the selection of, an alternate stable lubricant that is compatible with the fastener material and the environment prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Reactor Head Closure Studs Program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its audit and review of the applicant's Reactor Head Closure Studs Program, and the applicant's responses to the RAIs, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. The staff reviewed the exceptions and their justification, and finds that the exceptions were not warranted and that the AMP is adequate to manage the aging effects for which the LRA credits it. The staff identified an enhancement to the AMP and finds that with its implementation through commitmentNo. 3 prior to the period of extended operation, the existing program will be consistent with the GALL AMP with which it was compared. The staff concludes that the applicant has demonstrated that effects of aging will .be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.4 Flow-Accelerated Corrosion Summary of Technical Information in the Application. LRA Section B.2.1.6 describes the existing Flow-Accelerated Corrosion program as being consistent with an exception with GALL AMP XI.M17, "Flow-Accelerated Corrosion." The applicant stated that this program provides for predicting, detecting, and monitoring wall thinning in piping, fittings, valve bodies, and feedwater heaters due to flow-accelerated corrosion. The applicant also stated that program activities include analyses to determine critical locations, baseline inspections to determine the extent of thinning at these critical locations, and follow-up inspections to confirm the predictions. The applicant also stated that inspections are performedusing ultrasonic, radiographic, visual or other approved testing techniques capable of detecting wall thinning.3-44 to supplement its own AMP by completing industry recommendations and evaluations to address issues that have occurred at other plants. Additionally, the staff reviewed several industry operating experiences along with the resulting response taken by the applicant to apply the lessons learned to its own program and found the responses to be satisfactory. The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A1.2.3.1 O. The staff finds this program element acceptable. UFSAR Supplement. LRA section A2.1.3 provides the applicant's UFSAR Supplement for the Reactor Head Closure Studs Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR. In LRA Section A5, Commitment No.3, the applicant committed to credit the program for aging management during the period of extended operation. In its letter dated October 30, 2008, the applicant revised Commitment No.3 to incorporate the enhancement concerning the selection of I an alternate stable lubricant that is compatible with the fastener material and the environment prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Reactor Head Closure Studs Program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Reactor Head Closure Studs Program, and the applicant's responses to the RAls, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. The staff reviewed the exceptions and their justification, and finds that the exceptions were not warranted and that the AMP is adequate to manage the aging effects for which the LRA credits it. The staff identified an enhancement to the AMP and finds that with its implementation through commitment No.3 prior to the period of extended operation, the existing program will be consistent with the GALL AMP with which it was compared. The staff concludes that the applicant has demonstrated that effects of aging will ,be adequately managed so that the intended function( s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.4 Flow-Accelerated Corrosion Summary of Technical Information in the Application. LRA Section B.2.1.6 describes the existing Flow-Accelerated Corrosion program as being consistent with an exception with GALL AMP XI.M17, "Flow-Accelerated Corrosion." The applicant stated that this program provides for predicting, detecting, and monitoring wall thinning in piping, fittings, valve bodies, and feedwater heaters due to flow-accelerated corrosion. The applicant also stated that program activities include analyses to determine critical locations, baseline inspections to determine the extent of thinning at these critical locations, and follow-up inspections to confirm the predictions. The applicant also stated that inspections are performed using ultrasonic, radiographic, visual or other approved testing techniques capable of detecting wall thinning. 3-44 Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, remained adequate to manage the aging effects for which the LRA credits it.In comparing the program elements in the applicant's program to those in GALL AMP XI.M17, the staff determined that those applicant's program elements for which the applicant claimed consistency with the GALL Report, are consistent, but the staff identified an issue with the"monitoring and trending" program element.In the "monitoring and trending" program element, it was not clear to the staff what criteria the applicant used to determine when additional samples are required. GALL AMP XI.M17 recommends that results be evaluated to determine if additional inspections are needed. In RAI B.2.1.6-2, dated September 29, 2008, the staff requested that the applicant provide additionalinformation relating to the criteria used to determine when additional samples are required.In its response to the RAI dated October 20, 2008, the applicant stated that if any component has a current or projected wall thickness within the next operating cycle that is less than the minimum acceptable wall thickness, or if any component exhibits unexpected wall thinning, then sample expansion is required to bound the area of thinning. The applicant provided examples of increased sample scope, such as increasing the sample scope to include two pipe diameters downstream and upstream of degraded component, the two highest ranked components based on wear rate projections from the same train, and components of similar geometry in sister trains.The applicant also stated that if the initial sample expansion inspection detects components with significant wear, then the inspection scope is further expanded until no additional components with significant wear are detected.Based on its review, the staff finds the applicant's response to RAI B.2.1.6-2 acceptable because the applicant provided the criteria that are used to determine sample expansion. The staff finds that the sample expansion scope includes the appropriate locations to determine the extent of degraded components which is consistent with the recommendation of GALL AMP XI.M17 to evaluate the results of the inspection to determine if additional inspections are needed. The staffs concern described in RAI B.2.1.6-2 is resolved.Exception. The LRA states an exception to the GALL Report as follows: NUREG-1801 specifies in XI.M17 that the program relies on implementation of the Electric Power Research Institute (EPRI) guidelines in the Nuclear Safety Analysis Center (NSAC)-202L-R2 for an effective FAC program. The TMI-1 FAC Program is based on the EPRI guidelines found in NSAC-202L-R3. The sections of NSAC-202L associated with the program elements were reviewed to show that revision 2 and 3 of the guidelines are equivalent with one difference: revision 3 allows an additional method for determining the wear of piping components from UT inspection. This method is called the Averaged Band Method. TMI-1 does not use this method at this time. By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program," "preventive actions," "detection of aging effects," "monitoring and trending,""acceptance criteria," and "corrective actions" program elements.3-45 Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, remained adequate to manage the aging effects for which the LRA credits it. In comparing the program elements in the applicant's program to those in GALL AMP XI.M17, the staff determined that those applicant's program elements for which the applicant claimed consistency with the GALL Report, are consistent, but the staff identified an issue with the "monitoring and trending" program element. In the "monitoring and trending" program element, it was not clear to the staff what criteria the applicant used to determine when additional samples are required. GALL AMP XI.M17 recommends that results be evaluated to determine if additional inspections are needed. In RAI B.2.1.6-2, dated September 29, 2008, the staff requested that the applicant provide additional information relating to the criteria used to determine when additional samples are required. In its response to the RAI dated October 20, 2008, the applicant stated that if any component has a current or projected wall thickness within the next operating cycle that is less than the minimum acceptable wall thickness, or if any component exhibits unexpected wall thinning, then sample expansion is required to bound the area of thinning. The applicant provided examples of increased sample scope, such as increasing the sample scope to include two pipe diameters downstream and upstream of degraded component, the two highest ranked components based on wear rate projections from the same train, and components of similar geometry in sister trains. The applicant also stated that if the initial sample expansion inspection detects components with significant wear, then the inspection scope is further expanded until no additional components with significant wear are detected. Based on its review, the staff finds the applicant's response to RAI B.2.1.6-2 acceptable because the applicant provided the criteria that are used to determine sample expansion. The staff finds that the sample expansion scope includes the appropriate locations to determine the extent of degraded components which is consistent with the recommendation of GALL AMP XI.M17 to evaluate the results of the inspection to determine if additional inspections are needed. The staffs concern described in RAI B.2.1.6-2 is resolved. Exception. The LRA states an exception to the GALL Report as follows: NUREG-1801 specifies in XI.M17 that the program relies on implementation of the Electric Power Research Institute (EPRI) guidelines in the Nuclear Safety Analysis Center (NSAC)-202L-R2 for an effective FAC program. The TMI-1 FAC Program is based on the EPRI guidelines found in NSAC-202L-R3. The sections of NSAC-202L associated with the program elements were reviewed to show that revision 2 and 3 of the guidelines are equivalent with one difference: revision 3 allows an additional method for determining the wear of piping components from UT inspection. This method is called the Averaged Band Method. TMI-1 does not use this method at this time. By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program," "preventive actions," "detection of aging effects," "monitoring and trending," "acceptance criteria," and "corrective actions" program elements. 3-45 The staff reviewed the applicant's program basis document that references procedure ER-AA-430, "Conduct of Flow Accelerated Corrosion Activities," which utilizes NSAC-202L-R2 as a guideline. In RAI B.2.1.6-1 dated September 29, 2008, the staff requested that the applicantprovide additional information to clarify the discrepancy between the flow-accelerated corrosion activities procedure, which references NSAC-202L-R2 and the LRA exception, which references NSAC-202L-R3. The staff also requested that the applicant provide additional information to indicate if there are any plans to use the Averaged Band Method for determining the wear of piping components from UT inspections in the future, and if so, what additional controls will be put in place to utilize this method.In its response to the RAI dated October 20, 2008, the applicant stated that the Flow Accelerated Corrosion Program will rely on the implementation of EPRI guideline NSAC-202L-R3 and the procedure ER-AA-430 will be revised to identify that the program is in accordance with EPRI guideline NSAC-202L-R3. The applicant also stated that it is currently transitioning to allow the use of the Averaged Band Method for determining wear of piping components from UT inspections as described in NSAC-202L-R3. Accordingly, the applicant amended the LRA to delete the last sentence of the exception that states, "TMI-1 does not use this method at this time," and replaced it with the following text: This method is a deviation of the Band Method and builds upon years of experience with the Band Method, which remains an option in NSAC-202L-R3 for determining the wear of piping components from UT inspection. Overly conservative methods can lead to unnecessary inspections or re-inspections. The Averaged Band Method provides a more accurate and less conservative estimate of pipe wear than the Band Method.Based on its review, the staff finds the applicant's response to RAI B.2.1.6-1 acceptable and also finds the exception to the GALL Report acceptable because the applicant intends to use the Averaged Band Method as delineated in NSAC-202L-R3, for determining the wear of piping components from UT inspections. In addition, GALL AMP XI.M17 acknowledges that the program relies on implementation of EPRI guidelines in NSAC-202L-R2 for an effective flow-accelerated corrosion program and the staff notes that NSAC-202L-R3 provides another option of determiningthe wear of piping components from UT inspections. The staff notes that EPRI documents are created using industry experience over several years and finds that the Averaged Band Method will provide another method to determine the wear of piping components from UT inspections. The staff finds this method to be more accurate, thereby resulting in better prediction of remaining life and less rework. The staff finds the use of EPRI NSAC-202L-R3 acceptable. The staff's concern described in RAI B.2.1.6-1 is resolved.Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.6 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant stated that during the 2003 refueling outage, flow-accelerated corrosion (FAC)inspections of several components were found to have experienced wall-thinning. The applicant analyzed these components to establish a safe life expectancy for continued operation until 2005.These components were subsequently replaced in 2005. In addition, the applicant found some components were experiencing high wear rates and these components were replaced and 3-46 The staff reviewed the applicant's program basis document that references procedure ER-AA-430, "Conduct of Flow Accelerated Corrosion Activities," which utilizes NSAC-202L-R2 as a guideline. In RAI B.2.1.6-1 dated September 29, 2008, the staff requested that the applicant provide additional information to clarify the discrepancy between the flow-accelerated corrosion activities procedure, which references NSAC-202L-R2 and the LRA exception, which references NSAC-202L-R3. The staff also requested that the applicant provide additional information to indicate if there are any plans to use the Averaged Band Method for determining the wear of piping components from UT inspections in the future, and if so, what additional controls will be put in place to utilize this method. In its response to the RAI dated October 20, 2008, the applicant stated that the Flow Accelerated Corrosion Program will rely on the implementation of EPRI guideline NSAC-202L-R3 and the procedure ER-AA-430 will be revised to identify that the program is in accordance with EPRI guideline NSAC-202L-R3. The applicant also stated that it is currently transitioning to allow the use of the Averaged Band Method for determining wear of piping components from UT inspections as described in NSAC-202L-R3. Accordingly, the applicant amended the LRA to delete the last sentence of the exception that states, "TMI-1 does not use this method at this time," and replaced it with the following text: This method is a deviation of the Band Method and builds upon years of experience with the Band Method, which remains an option in NSAC-202L-R3 for determining the wear of piping components from UT inspection. Overly conservative methods can lead to unnecessary inspections or re-inspections. The Averaged Band Method provides a more accurate and less conservative estimate of pipe wear than the Band Method. Based on its review, the staff finds the applicant's response to RAI B.2.1.6-1 acceptable and also finds the exception to the GALL Report acceptable because the applicant intends to use the Averaged Band Method as delineated in NSAC-202L-R3, for determining the wear of piping components from UT inspections. In addition, GALL AMP XI.M17 acknowledges that the program relies on implementation of EPRI guidelines in NSAC-202L-R2 for an effective flow-accelerated corrosion program and the staff notes that NSAC-202L-R3 provides another option of determining the wear of piping components from UT inspections. The staff notes that EPRI documents are created using industry experience over several years and finds that the Averaged Band Method will provide another method to determine the wear of piping components from UT inspections. The staff finds this method to be more accurate, thereby resulting in better prediction of remaining life and less rework. The staff finds the use of EPRI NSAC-202L-R3 acceptable. The staff's concern described in RAI B.2.1.6-1 is resolved. Operating Experience.- The staff reviewed the operating experience provided in LRA Section 8.2.1.6 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The applicant stated that during the 2003 refueling outage, flow-accelerated corrosion (FAC) inspections of several components were found to have experienced wall-thinning. The applicant analyzed these components to establish a safe life expectancy for continued operation until 2005. These components were subsequently replaced in 2005. In addition, the applicant found some components were experiencing high wear rates and these components were replaced and 3-46 changed to a resistant material in 2005. The applicant identified other instances of wall thinning in heater drain pump discharge lines and main feedwater pump recirculation lines. The applicant initiated appropriate corrective actions, which included replacing some piping.The staff finds that the applicant's Flow-Accelerated Corrosion Program, with the corrective actions discussed in the LRA, has been effective in identifying, monitoring, and correcting the effects of flow-accelerated corrosion and can be expected to ensure that piping wall thickness will be maintained above the minimum required by design.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. LRA Section A.2.1.6, provides the applicant's UFSAR Supplement for theFlow-Accelerated Corrosion Program. The staff confirmed that the UFSAR Supplement summary description for the Flow-Accelerated Corrosion Program conforms to the staff's recommended UFSAR Supplement for this program as found in SRP-LR Table 3.4-2.In LRA Section A.5, Commitment No. 6, the applicant committed to implementation of the Flow-Accelerated Corrosion Program on an on-going basis during the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Flow-Accelerated Corrosion Program as required by 10 CFR 54.21(d).Conclusion. On the basis of its review of the applicant's Flow-Accelerated Corrosion Program and the applicant's response to the RAIs, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and its justification and finds that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this program and concludes that the applicant has provided an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.5 Open-Cycle Cooling Water System Summary of Technical Information in the Application. LRA Section B.2.1.9 describes the existing Open-Cycle Cooling Water System Program as being consistent, with an exception and an enhancement, to GALL AMP XI.M20, "Open-Cycle Cooling Water System." The applicant stated that the program provides for management of aging effects in raw water cooling systems through tests and inspections per guidelines of NRC Generic Letter (GL) 89-13,"Service Water Problems Affecting Safety Related Components." The program primarily consists of GL 89-13 activities that include chemical and biocide injection, system testing, periodic inspections and NDE. The applicant also stated that the program includes surveillance and control techniques to manage aging effects caused by biofouling, corrosion, erosion, protective coating failures, and silting in Open-Cycle Cooling Water (OCCW) system components that are exposed to a raw water environment. The applicant also stated that procedures provide instructions and controls for preventive actions through raw water chemistry control (chemical and biocide injection), performance monitoring through station testing and condition monitoring, and 3-47 changed to a resistant material in 2005. The applicant identified other instances of wall thinning in heater drain pump discharge lines and main feedwater pump recirculation lines. The applicant initiated appropriate corrective actions, which included replacing some piping. The staff finds that the applicant's Flow-Accelerated Corrosion Program, with the corrective actions discussed in the LRA, has been effective in identifying, monitoring, and correcting the effects of flow-accelerated corrosion and can be expected to ensure that piping wall thickness will be maintained above the minimum required by design. The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1

o. The staff finds this program element acceptable.

UFSAR Supplement. LRA Section A.2.1.6, provides the applicant's UFSAR Supplement for the Flow-Accelerated Corrosion Program. The staff confirmed that the UFSAR Supplement summary description for the Flow-Accelerated Corrosion Program conforms to the staff's recommended UFSAR Supplement for this program as found in SRP-LR Table 3.4-2. In LRA Section A.5, Commitment No.6, the applicant committed to implementation of the Accelerated Corrosion Program on an on-going basis during the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Accelerated Corrosion Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's Flow-Accelerated Corrosion Program and the applicant's response to the RAls, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and its justification and finds that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this program and concludes that the applicant has provided an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.5 Open-Cycle Cooling Water System Summary of Technical Information in the Application. LRA Section B.2.1.9 describes the existing Open-Cycle Cooling Water System Program as being consistent, with an exception and an enhancement, to GALL AMP XI.M20, "Open-Cycle Cooling Water System." The applicant stated that the program provides for management of aging effects in raw water cooling systems through tests and inspections per guidelines of NRC Generic Letter (GL) 89-13, "Service Water Problems Affecting Safety Related Components." The program primarily consists of GL 89-13 activities that include chemical and biocide injection, system testing, periodic inspections and NDE. The applicant also stated that the program includes surveillance and control techniques to manage aging effects caused by biofouling, corrosion, erosion, protective coating failures, and silting in Open-Cycle Cooling Water (OCCW) system components that are exposed to a raw water environment. The applicant also stated that procedures provide instructions and controls for preventive actions through raw water chemistry control (chemical and biocide injection), performance monitoring through station testing and condition monitoring, and 3-47 leak detection through inspection and testing of raw water systems within the scope of license renewal.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception and the enhancement to determine whether the AMP, with the exception and the enhancement, remained adequate to manage the aging effects for which the LRA credits it.In comparing the elements in the applicant's program to those in GALL AMP XI.M20, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. Exception. The LRA states an exception to the GALL Report as follows: NUREG-1 801 program scope consists of preventive measures to mitigate the aging effects of material loss and fouling due to micro- or macro-organisms and various corrosion mechanisms. The TMI-1 Open-Cycle Cooling Water System aging management program will also be used to manage the following aging effects and mechanisms for the internal surfaces of concrete circulating water piping: 0 Cracking and expansion due to reaction with aggregates 0 Cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel* Increase in porosity and permeability, cracking, loss of material (spalling, scaling) due to aggressive chemical attack* Increase in porosity and permeability, loss of strength due to leaching of calcium hydroxide The TMI-1 Open-Cycle Cooling Water System aging management program activities are adequate for managing the aging effects of the internal surfaces of concrete circulating water piping.By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program," "parameters monitored/inspected," and "detection of aging effects," program elements.The staff noted that the applicant has proposed the use of the Open-Cycle Cooling Water System Program to manage the aging of the concrete circulating water tunnel, which is similar to concrete structures for which the GALL Report recommends use of the Structures Monitoring Program and for which the GALL Report recommends further evaluation of the program if the Structures Monitoring Program is not used. In RAI B.2.1.9-1, dated September 29, 2008, the staff requestedthat the applicant provide additional information to support evaluating the adequacy of the Open-Cycle Cooling Water System Program to manage the additional aging effects for which the program is credited.In its response to the RAI dated October 20, 2008, the applicant stated that the Open-Cycle Cooling Water System Program credits internal walkdown and inspections of the concrete 3-48 leak detection through inspection and testing of raw water systems within the scope of license renewal. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception and the enhancement to determine whether the AMP, with the exception and the enhancement, remained adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in GALL AMP XI.M20, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. Exception. The LRA states an exception to the GALL Report as follows: NUREG-1B01 program scope consists of preventive measures to mitigate the aging effects of material loss and fouling due to micro-or macro-organisms and various corrosion mechanisms. The TMI-1 Open-Cycle Cooling Water System aging management program will also be used to manage the following aging effects and mechanisms for the internal surfaces of concrete circulating water piping:

  • Cracking and expansion due to reaction with aggregates
  • Cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel
  • Increase in porosity and permeability, cracking, loss of material (spalling, scaling) due to aggressive chemical attack .
  • Increase in porosity and permeability, loss of strength due to leaching of calcium hydroxide

.. The TMI-1 Open-Cycle Cooling Water System aging management program activities are adequate for managing the aging effects of the internal surfaces of concrete circulating water piping. By letter dated October 30, 200B, the applicant stated that this exception applies tDthe "scope of program," "parameters monitored/inspected," and "detection of aging effects," program elements. The staff noted that the applicant has proposed the use of the Open-Cycle Cooling Water System Program to manage the aging of the concrete circulating water tunnel, which is similar to concrete structures for which the GALL Report recommends use of the Structures Monitoring Program and for which the GALL Report recommends further evaluation of the program if the Structures Monitoring Program is not used. In RAI B.2.1.9-1, dated September 29, 200B, the staff requested that the applicant provide additional information to support evaluating the adequacy of the Cycle Cooling Water System Program to manage the additional aging effects for which the program is credited. In its response to the RAI dated October 20, 200B, the applicant stated that the Open-Cycle Cooling Water System Program credits internal walkdown and inspections of the concrete 3-4B circulating water piping and tunnels for license renewal. The applicant stated that the current conditions of the piping and tunnels are known and have been documented with photographs. The applicant stated that inspections performed during the Fall 2003 refueling outage identified degraded caulking at seven piping joints, and that inspections performed during the Fall 2005 refueling outage found no significant increase in degradation at those same seven joints and no degradation in other locations throughout the concrete piping and tunnels. The applicant stated that conditions of the degraded joints are documented and planned repairs are tracked in itscorrective action program and that no other degradation has been identified throughout the concrete circulating water piping and tunnels. The applicant stated that the Structures Monitoring Program also credits the walkdown and inspection of the concrete circulating water tunnels and that internal inspection of the circulating water concrete tunnels, which requires drainage of the circulating water system, is required every five years by the Structures Monitoring Program.In its response to the RAI, the applicant stated that internal inspection of the circulating water piping credited by the Open-Cycle Cooling Water System Program is performed when the circulating water system is drained, and that the system typically is drained every refueling outage to perform de-silting of the cooling tower basins. The applicant stated that this activity includes walkdown and general visual examination of the entire length of the piping and tunnels between the main circulating water pump discharge and the main condenser inlet and between the main condenser outlet and the natural draft cooling towers. The applicant stated that a general visual examination is utilized for detection of all aging mechanisms identified in the LRA for the internal surfaces of the concrete circulating water piping and tunnels.The staff noted that the applicant has existing operating experience inspecting the circulating water tunnel and concrete piping to monitor for aging effects. The staff also noted that the aging effects being monitored manifest themselves in readily noticeable indications such as degraded pipe joint caulking and concrete surface damage or discoloration, and that visual inspection is adequate to detect degradation of the concrete components and structures. The staff further noted that current conditions of the circulating water tunnel and concrete piping are documented, and that any future age-related degradation can be identified and evaluated by comparison with the currently documented baseline conditions. Based on its review, the staff finds the applicant's response to RAI B.2.1.9-1 acceptable and also finds the exception to the GALL Report acceptable because the applicant's proposed inspectionmethodology and frequency is adequate to detect the aging effects of interest, and the components included in those inspections are part of the station's open-cycle cooling water system. Additionally, the staff finds the applicant's expansion of the OCCW System Program to include monitoring for additional aging effects to be acceptable. The staff's concern described in RAI B.2.1.9-1 is resolved.Enhancement. The LRA states an enhancement to the GALL Report as follows: A new river water chemical treatment system will be installed to treat the river water systems for biofouling, including microbiologically-influenced (MIC) corrosion. By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program," "preventive actions," and "acceptance criteria" program elements.In LRA Section A.5, Commitment 9, the applicant committed to add the new river water chemical treatment system prior to the period of extended operation. 3-49 circulating water piping and tunnels for license renewal. The applicant stated that the current conditions of the piping and tunnels are known and have been documented with photographs. The applicant stated that inspections performed during the Fall 2003 refueling outage identified degraded caulking at seven piping joints, and that inspections performed during the Fall 2005 refueling outage found no significant increase in degradation at those same seven joints and no degradation in other locations throughout the concrete piping and tunnels. The applicant stated that conditions of the degraded joints are documented and planned repairs are tracked in its corrective action program and that no other degradation has been identified throughout the concrete circulating water piping and tunnels. The applicant stated that the Structures Monitoring Program also credits the walkdown and inspection of the concrete circulating water tunnels and that internal inspection of the circulating water concrete tunnels, which requires drainage of the circulating water system, is required every five years by the Structures Monitoring Program. In its response to the RAI, the applicant stated that internal inspection of the circulating water piping credited by the Open-Cycle Cooling Water System Program is performed when the circulating water system is drained, and that the system typically is drained every refueling outage to perform de-silting of the cooling tower basins. The applicant stated that this activity includes walkdown and general visual examination of the entire length of the piping and tunnels between the main Circulating water pump discharge and the main condenser inlet and between the main condenser outlet and the natural draft cooling towers. The applicant stated that a general visual examination is utilized for detection of all aging mechanisms identified in the LRA for the internal surfaces of the concrete circulating water piping and tunnels. The staff noted that the applicant has existing operating experience inspecting the circulating water tunnel and concrete piping to monitor for aging effects. The staff also noted that the aging effects being monitored manifest themselves in readily noticeable indications such as degraded pipe joint caulking and concrete surface damage or discoloration, and that visual inspection is adequate to detect degradation of the concrete components and structures. The staff further noted that current conditions of the circulating water tunnel and concrete piping are documented, and that any future age-related degradation can be identified and evaluated by comparison with the currently documented baseline conditions. Based on its review, the staff finds the applicant's response to RAI B.2.1.9-1 acceptable and also finds the exception to the GALL Report acceptable because the applicant's proposed inspection methodology and frequency is adequate to detect the aging effects of interest, and the components included in those inspections are part of the station's open-cycle cooling water system. Additionally, the staff finds the applicant's expansion of the OCCW System Program to include monitoring for additional aging effects to be acceptable. The staff's concern described in RAI B.2.1.9-1 is resolved. Enhancement. The LRA states an enhancement to the GALL Report as follows: A new river water chemical treatment system will be installed to treat the river water systems for biofouling, including microbiologically-influenced (MIC) corrosion. By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program," "preventive actions," and "acceptance criteria" program elements. In LRA Section A.5, Commitment 9, the applicant committed to add the new river water chemical treatment system prior to the period of extended operation. 3-49 The staff noted that the change proposed by the applicant is not needed to cure a deficiency in the current program or to bring the current program into conformance with the recommendations for an Open-Cycle Cooling Water System Program as described in GALL AMP XI.M20. The staff noted that the applicant's current OCCW system design includes equipment to treat the river water systems for biofouling. However, the applicant stated that the existing river water treatment system has experienced some operational issues that will be eliminated by the new river water treatment system design.Based on its review, the staff finds the applicant's proposed enhancement to be acceptable because the program elements in the applicant's Open-Cycle Cooling Water System Program that are affected by this enhancement will be consistent with the recommended program elements in GALL AMP XI.M20, and the addition of a river water treatment system that has improved operational features increases confidence that the applicant's program will successfully mitigate potential aging effects for components within its scope during the period of extended operation. Operatingq Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.9 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant stated that guidance of NRC GL 89-13 has been implemented for approximately 10 years and has been effective in managing aging effects due to biofouling, corrosion, erosion,protective coating failure, and silting in structures and components serviced by the OCCW systems. The applicant stated that loss of material due to general, pitting, crevice and microbiologically-influenced corrosion, and fouling, reduction of heat transfer due to fouling, cracking and expansion due to reaction with aggregates, cracking, loss of bond, and loss ofmaterial (spalling, scaling) due to corrosion of embedded steel, increase in porosity and permeability, cracking, loss of material (spalling, scaling) due to aggressive chemical attack, increase in porosity and permeability, and loss of strength due to leaching of calcium hydroxide are being adequately managed- The applicant provided the following three examples of site-specific operating experience to demonstrate effectiveness of the current Open-Cycle Cooling Water System Program: (1) The applicant stated that in November 2001, eddy current testing on a closed cooling water heat exchanger resulted in identification of indications in 10 of 369 tubes inspected. Indications ranged from 21% to 50% through-wall with two indications greater than 45%through-wall. The applicant stated that the two tubes with the larger indications were plugged to reduce risk of possible leakage during the next operating cycle, and a root cause investigation found that 8 of the 10 tubeswith indications were newly installed during the previous refueling outage. The applicant further stated that the investigation concluded that the most significant mode of degradation was under-deposit corrosion, based on the identification of silt in the lower half of the heat exchanger and that MIC and MIC-related ammonia-induced cracking was considered a contributing mode of degradation because seasonal ammonia was present in the river.(2) The applicant stated that in June 2002, a through-wall leak was identified in the 30-inch circulating water pipe, and the leak size was estimated to be 1 gpm. The applicant stated 3-50 The staff noted that the change proposed by the applicant is not needed to cure a deficiency in the current program or to bring the current program into conformance with the recommendations for an Open-Cycle Cooling Water System Program as described in GALL AMP XI.M20. The staff noted that the applicant's current OCCW system design includes equipment to treat the river water systems for biofouling. However, the applicant stated that the existing river water treatment system has experienced some operational issues that will be eliminated by the new river water treatment system design. Based on its review, the staff finds the applicant's proposed enhancement to be acceptable because the program elements in the applicant's Open-Cycle Cooling Water System Program that are affected by this enhancement will be consistent with the recommended program elements in GALL AMP XI.M20, and the addition of a river water treatment system that has improved operational features increases confidence that the applicant's program will successfully mitigate potential aging effects for components within its scope during the period of extended operation. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.9 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The applicant stated that guidance of NRC GL 89-13. has been implemented for approximately 10 years and has been effective in managing aging effects due to biofouling, corrosion, erosion, protective coating failure, and silting in structures and components serviced by the OCCW systems. The applicant stated that loss of material due to general, pitting, crevice and microbiologically-influenced corrosion, and fouling, reduction of heat transfer due to fouling, cracking and expansion due to reaction with aggregates, cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel, increase in porosity and permeability, cracking, loss of material (spalling, scaling) due to aggressive chemical attack, increase in porosity and permeability, and loss of strength due to leaching of calcium hydroxide are being adequately managed: The applicant provided the following three examples of specific operating experience to demonstrate effectiveness of the current Open-Cycle Cooling Water System Program: . (1) The applicant stated that in November 2001, eddy current testing on a closed cooling water heat exchanger resuHed in identification of indications in 10 of 369 tubes inspected. Indications ranged from 21 % to 50% through-wall with two indications greater than 45% through-wall. The applicant stated that the two tubes with the larger indications were plugged to reduce risk of possible leakage during the next operating cycle, and a root cause investigation found that 8 of the 10 tubeswith indications were newly installed during the previous refueling outage. The applicant further stated that the investigation concluded that the most significant mode of degradation was under-deposit corrosion, based on the identification of silt in the lower half of the heat exchanger and that MIC and MIC-related ammonia-induced cracking was cOr;1sidered a contributing mode of degradation because seasonal ammonia was present in the river. (2) The applicant stated that in June 2002, a through-wall leak was identified in the 30-inch circulating water pipe, and the leak size was estimated to be 1 gpm. The applicant stated 3-50 that indications on the surface of the pipe suggested MIC was the likely cause of the leak.The applicant further stated that technical evaluations concluded that the leak did not jeopardize the capabilities of the circulating water system, which provides cooling to the main condenser and the feedwater pump turbine condensers; and due to the orientation of the leak there was no potential impact on nearby equipment, including valve motor operators. The applicant stated that repairs of the pipe were completed in a subsequent outage.(3) The applicant stated that in December 2005, a MIC-related leak was found in the cross-tie line between two OCCW subsystems and that the leak was in a carbon steel pipe in a low flow area. The applicant stated that ultrasonic testing (UT) was performed on the leak area and results showed acceptable wall thickness except at the location of the leak. The applicant stated that per ASME code case requirements, UT examinations were required every 90 days until the leak was repaired, that subsequent UT examinations showed no further degradation beyond the original failure; and the piping where the leak occurred was replaced during the outage in the fall of 2007.The applicant stated that problems identified in the operating experience of the OCCW System Program would not affect safe operation of the plant, and adequate corrective actions were taken to prevent recurrence. In addition to these examples, the staff reviewed the applicant's operating experience discussion provided in the applicant's license renewal program basis document binder for the Open-Cycle Cooling Water System Program. The staff reviewed additional selected corrective ARs related to the Open-Cycle Cooling Water System Program and interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. Based on this review, the staff finds (1) the OE demonstrates that the Open-Cycle Cooling Water System Program is achieving its objective of managing the aging effects of loss of material (without credit for protective coatings) and buildup of deposits (including fouling from biological, corrosion product, and external sources) in system components exposed to a raw water environment; and (2) that the applicant is taking appropriate corrective actions through implementation of the program.The staff confirmed the "operating experience" program element satisfies the criterion defined in the GALL Report and SRP-LR Section A. 1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. LRA Section A.2.1.9 provides the applicant's UFSAR Supplement for the Open-Cycle Cooling Water System Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staffs recommended UFSAR Supplement guidance found in SRP-LR Table 3.3-2.In LRA Section A.5, Commitment No. 9, the applicant committed to credit the program for aging management during the period of extended operation and also committed to the program enhancement related to the installation of a new river water chemical treatment system prior to the period of extended operation. 3-51 that indications on the surface of the pipe suggested MIC was the likely cause of the leak. The applicant further stated that technical evaluations concluded that the leak did not jeopardize the capabilities of the circulating water system, which provides cooling to the main condenser and the feedwater pump turbine condensers; and due to the orientation of the leak there was no potential impact on nearby equipment, including valve motor operators. The applicant stated that repairs of the pipe were completed in a subsequent (3) The applicant stated that in December 2005, a MIC-related leak was found in the cross-tie line between two OCCW subsystems and that the leak was in a carbon steel pipe in a low flow area. The applicant stated that ultrasonic testing (UT) was performed on the leak area and results showed acceptable wall thickness except at the location of the leak. The applicant stated that per ASME code case requirements, UT examinations were required every 90 days until the leak was repaired, that subsequent UT examinations showed no further degradation beyond the original failure; and the piping where the leak occurred was replaced during the outage in the fall of 2007. The applicant stated that problems identified in the operating experience of the OCCW System Program would not affect safe operation of the plant, and adequate corrective actions were taken to prevent recurrence. In addition to these examples, the staff reviewed the applicant's operating experience discussion provided in the applicant's license renewal program basis document binder for the Open-Cycle Cooling Water System Program. The staff reviewed additional selected corrective ARs related to the Open-Cycle Cooling Water System Program and interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. Based on this review, the staff finds (1) the OE demonstrates that the Open-Cycle Cooling Water System Program is achieving its objective of managing the aging effects of loss of material (without credit for protective coatings) and buildup of deposits (including fouling from biological, corrosion product, and external sources) in system components exposed to a raw water environment; and (2) that the applicant is taking appropriate corrective actions through implementation of the program. The staff confirmed the "operating experience" program element satisfies the criterion defined in the GALL Report and SRP-LR Section A1.2.3.1 o. The staff finds this program element acceptable. UFSAR Supplement. LRA Section A2.1.9 provides the applicant's UFSAR Supplement for the Open-Cycle Cooling Water System Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in SRP-LR Table 3.3-2. In LRA Section AS, Commitment No.9, the applicant committed to credit the program for aging management during the period of extended operation and also committed to the program enhancement related to the installation of a new river water chemical treatment system prior to the period of extended operation. 3-51 The staff finds that the applicant has provided an adequate summary description of the Open-Cycle Cooling Water System Program as required by 10 CFR 54.21(d).Conclusion. On the basis of its review of the applicant's Open-Cycle Cooling Water SystemProgram, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exception and its justification and finds that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. The staff also reviewed the enhancement and its justification and finds that with itsimplementation through Commitment No. 9 prior to the period of extended operation, the existing program will be consistent with the GALL AMP with which it was compared. The staff also reviewed the response to RAI 2.1.9-1 and finds it acceptable. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.6 Closed-Cycle Cooling Water System Summary of Technical Information in the Application. LRA Section B.2.1.10 describes the existing Closed-Cycle Cooling Water System Program as being consistent, with an exception and an enhancement, to GALL AMP XI.M21, "Closed-Cycle Cooling Water System." The applicant stated that this program provides aging management for loss of material and/or reduction of heat transfer in piping, piping components, piping elements and heat exchangers within the scope of license renewal that are in a closed cooling water environment. The applicant also stated that the program provides for preventive maintenance, performance monitoring and condition monitoring activities for affected components. The applicant further stated that performance monitoring provides indications of degradation in closed-cycle cooling water (CCCW) systems, with plant operating conditions providing indications of degradation in normally operating systems, and that station maintenance inspections and NDE provide condition monitoring of heat exchangers exposed to CCCW environments. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception and the enhancement to determine whether the AMP, with the exception and the enhancement, remained adequate to manage the aging effects for which the LRA credits it.In comparing the elements in the applicant's program to those in GALL AMP XI.M21, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. Exception. The LRA states an exception to the GALL Report as follows: NUREG-1801 refers to EPRI TR-107396 1997 Revision. TMI-1 implements the guidance provided in EPRI 1007820, which is the 2004 Revision to TR-107396. EPRI periodically updates industry water chemistry guidelines, as new information becomes available. TMI-1 has reviewed EPRI 1007820 and has determined that the most significant difference is that the new revision provides more prescriptive guidance and has a more conservative monitoring approach. EPRI 1007820 meets the same requirements of EPRI TR-1 07396 for 3-52 The staff finds that the applicant has provided an adequate summary description of the Cycle Cooling Water System Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's Open-Cycle Cooling Water System Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exception and its justification and finds that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. The staff also reviewed the enhancement and its justification and finds that with its implementation through Commitment No.9 prior to the period of extended operation, the existing program will be consistent with the GALL AMP with which it was compared. The staff also reviewed the response to RAI 2.1.9-1 and finds it acceptable. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplementfor this AMP and concludes that the applicant has provided an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.6 Closed-Cycle Cooling Water System Summary of Technical Information in the Application. LRA Section B.2.1.10 describes the existing Closed-Cycle Cooling Water System Program as being consistent, with an exception and an enhancement, to GALL AMP XI.M21 , "Closed-Cycle Cooling Water System." The applicant stated that this program provides aging management for loss of material and/or reduction of heat transfer in piping, piping components, piping elements and heat exchangers within the scope of license renewal that are in a closed cooling water environment.* The applicant also stated that the program provides for preventive maintenance, performance monitoring and condition monitoring activities for affected components. The applicant further stated that performance monitoring provides indications of degradation in closed-cycle cooling water (CCCW) systems, with plant operating conditions providing indications of degradation in normally operating systems, and that station maintenance inspections and NDE provide condition monitoring of heat exchangers exposed to CCCW environments. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception and the enhancement to determine whether the AMP, with the exception and the enhancement, remained adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in GALL AMP XI.M21, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. Exception. The LRA states an exception to the GALL Report as follows: NUREG-1801 refers to EPRI TR-107396 1997 Revision. TMI-1 implements the guidance provided in EPRI1007820, which is the 2004 Revisfon to TR-107396. EPRI periodically updates industry water chemistry guidelines, as new information becomes available. TMI-1 has reviewed EPRI 1007820 and has determined that the most significant difference is that the new revision provides more prescriptive guidance and has a more conservative monitoring approach. EPRI1007820 meets thesame requirements of EPRI TR-107396 for 3-52 maintaining conditions to minimize corrosion and microbiological growth in closed cooling water systems for effectively mitigating many aging effects.By letter dated October 30, 2008, the applicant stated that this exception applies to the"preventive actions," "parameters monitored/inspected," and "monitoring and trending,' program elements.The staff noted that in a previous staff review and comparison of EPRI TR-1007820 and EPRI TR-1 07396, the staff confirmed an applicant's assessment that a more recent revision to EPRI's Closed-Cycle Cooling Water Chemistry Guidelines provides more prescriptive guidance, has a more conservative monitoring approach, and meets the same recommendations for maintaining conditions to minimize corrosion and microbiological growth in CCCW systems.Based on the previous staff review of EPRI TR-1 007820 having found the more recent ERPI Closed Cycle Cooling Water Chemistry Guidelines to be acceptable as a basis for aging management of CCCW systems and components with more prescriptive and conservative guidance than the guidelines referenced in the GALL Report, the staff finds the applicant's exception to the GALL Report acceptable. Enhancement. The LRA states an enhancement to the GALL Report as follows: A one-time inspection of selected components in stagnant flow areas will be conducted to confirm the absence of aging effects resulting from exposure to closed cycle cooling water.Also, a one-time inspection of selected CCCW chemical mix tanks and associated piping components will be performed to verify corrosion has not occurred on the interior surfaces of the tanks and associated piping components. By letter dated October 30, 2008, the applicant stated that this enhancement applies to the"parameters monitored/inspected," "detection of aging effects," and "acceptance criteria" program elements.In LRA Section A.5, Commitment No. 10, the applicant committed to implement the one-time inspections of CCCW components prior to the period of extended operation. The staff noted that the enhancement is a one-time expansion of the Closed-Cycle Cooling Water System Program's inspection scope to include stagnant flow areas and additional components and that this enhancement is not needed to eliminate a deficiency in the applicant's current program or to bring the applicant's current program into conformance with recommendations foran acceptable Closed-Cycle Cooling Water System Program as described in the GALL Report AMP XI.M21. However, the additional one-time inspections proposed by the applicant will provide additional confirmation that CCCW chemistry is being controlled in such a way as to mitigate or prevent potential aging effects in components exposed to the treated water of the CCCW system.Based on its review, the staff finds the applicant's proposed enhancement to be acceptable because the program elements in the applicant's Closed-Cycle Cooling Water System Program that are affected by this enhancement will be consistent with the program elements in GALL AMP XI.M21. In addition, the one-time inspection of stagnant flow areas and additional components will provide additional confirmation and increased confidence that the applicant'sprogram mitigates and prevents potential aging effects for components within its scope during the period of extended operation. 3-53 maintaining conditions to minimize corrosion and microbiological growth in closed cooling water systems for effectively mitigating many aging effects. By letter dated October 30, 2008, the applicant stated that this exception applies to the "preventive actions," "parameters monitored/inspected," and and program elements. The staff noted that in a previous staff review and comparison of EPRJ and EPRI TR-107396, the staff confirmed an applicant's assessment that a more recent revision to EPRl's Closed-Cycle Cooling Water Chemistry Guidelines provides more prescriptive guidance, has a more conservative monitoring approach, and meets the same recommendations for maintaining conditions to minimize corrosion and microbiological growth in CCCW systems. Based on the previous staff review of EPRI TR-1 007820 having found the more recent ERPI Closed Cycle Cooling Water Chemistry Guidelines to be acceptable as a basis for aging management of CCCW systems and components with more prescriptive and conservative guidance than the guidelines referenced in the GALL Report, the staff finds the applicant's exception to the GALL Report acceptable. Enhancement. The LRA states an enhancement to the GALL Report as follows: A one-time inspection of selected components in stagnant flow areas will be conducted to confirm the absence of aging effects resulting from exposure to closed cycle cooling water. Also, a one-time inspection of selected CCCW chemical mix tanks and associated piping components will be performed to verify corrosion has not occurred on the interior surfaces of the tanks and associated piping components. By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "parameters monitored/inspected," "detection of aging effects," and "acceptance criteria" program elements. In LRA Section A.5, Commitment No. 10, the applicant committed to implement the one-time inspections of CCCW components prior to the period of extended operation. The staff noted that the enhancement is a one-time expansion of the Closed-Cycle Cooling Water System Program's inspection scope to include stagnant flow areas and additional components and that this enhancement is not needed to eliminate a deficiency in the applicant's current program or to bring the applicant's current program into conformance with recommendations for an acceptable Closed-Cycle Cooling Water System Program as described in the GALL Report AMP XI.M21. However, the additional one-time inspections proposed by the applicant will provide additional confirmation that CCCW chemistry is being controlled in such a way as to mitigate or prevent potential aging effects in components exposed to the treated water of the CCCW system. Based on its review, the staff finds the applicant's proposed enhancement to be acceptable because the program elements in the applicant's Closed-Cycle Cooling Water System Program that are affected by this enhancement will be consistent with the program elements in GALL AMP XI.M21. In addition, the one-time inspection of stagnant flow areas and additional components will provide additional confirmation and increased confidence that the applicant's . program mitigates and prevents potential aging effects for components within its scope during the period of extended operation. 3-53 Operatinq Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.10 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmedthat the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant stated that degradation of CCCW systems due to corrosion product buildup or through-wall cracks in supply lines has been observed in operating plants and that operating experience demonstrates the need for this program. The applicant stated that cracking due to stress corrosion cracking, loss of material due to general, pitting, crevice, and galvanic corrosion, and reduction in heat transfer due to fouling is being adequately managed by the existing program. The applicant provided the following three examples of site-specific operating experience to demonstrate effectiveness of the current Closed-Cycle Cooling Water System Program: (1) The applicant stated that in February 2003, molybdate values fell below the minimum limit during a system flush of the decay heat closed cooling water system. The applicant stated that a planned system flush is needed periodically because the biocides used contribute to the chloride concentration in the system, and the chloride builds up after multiple biocide additions. The applicant further stated that molybdate concentration dropped below the minimum specified value for a short time during the nine-hour flushing process; however,an evaluation showed that the carbon steel was protected during the nine-hour period of time. The applicant stated that the system was protected during the flush and actions taken to minimize the out-of-specification time reduced risk of corrosion occurring because of the flush.(2) The applicant stated that in December 2002 routine water chemistry monitoring identified high chloride concentration in three CCCW subsystems, and the ammonia level exceeded the plant administrative goal of 2.0 ppm for CCCW for the first time since 1995. The applicant stated that subsequent evaluation found that samples of two biocides routinely added to the subsystems, when mixed at normal treatment concentrations, tested positive for ammonia in concentrations similar to those measured in the three affected subsystems. The applicant stated that corrective actions included reducing ammonia levels in the CCCW subsystems to normal levels and improving the product evaluation and procurement procedures used for the purchase of new treatment chemicals. (3) The applicant stated that in May 2002, weekly chemistry analysis of the CCCW system resulted in pH levels in three closed cooling subsystem below the specification limit. The applicant stated that chemistry recommendations were initiated to add sodium hydroxide to increase pH. The applicant further stated that follow-up testing showed the pH returned to acceptable levels and that there has been no occurrence of the CCCW system chemistry sample results being out of specification since 2003.In addition to these examples, the staff reviewed the applicant's operating experience discussion provided in the applicant's license renewal program basis document binder for the Closed-Cycle Cooling Water System Program. The staff reviewed additional selected corrective Action Reports related to the Closed-Cycle Cooling Water System Program and interviewed the applicant's 3-54 Operating Experience. The staff reviewed the operating experience provided in LRA Section 8.2.1.10 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experien<;e did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The applicant stated that degradation of CCCW systems due to corrosion product buildup or through-wall cracks in supply lines has been observed in operating plants and that operating experience demonstrates the need for this program. The applicant stated that cracking due to stress corrosion cracking, loss of material due to general, pitting, crevice, and galvanic corrosion, and reduction in heat transfer due to fouling is being adequately managed by the existing program. The applicant provided the following three examples of site-specific operating experience to demonstrate effectiveness of the current Closed-Cycle Cooling Water System Program: (1) The applicant stated that in February 2003, molybdate values fell below the minimum limit during a system flush of the decay heat closed cooling water system. The applicant stated that a planned system flush is needed periodically because the biocides used contribute to the chloride concentration in the system, and the chloride builds up after multiple biocide additions. The applicant further stated that molybdate concentration dropped below the minimum specified value for a short time during the nine-hour flushing process; however, an evaluation showed that the carbon steel was protected during the nine-hour period of time. The applicant stated that the system was protected during the flush and actions taken to minimize the out-of-specification time reduced risk of corrosion occurring because of the flush. (2) The applicant stated that in December 2002 routine water chemistry monitoring identified high chloride concentration in three CCCW subsystems, and the ammonia level exceeded the plant administrative goal of 2.0 ppm for CCCW for the first time since 1995. The applicant stated that subsequent evaluation found that samples of two biocides routinely added to the subsystems, when mixed at normal treatment concentrations, tested positive for ammonia in concentrations similar to those measured in the three affected subsystems. The applicant stated that corrective actions included reducing ammonia levels in the CCCW subsystems to normal levels and improving the product evaluation and procurement procedures used for the purchase of new treatment chemicals. (3) The applicant stated that in May 2002, weekly chemistry analysis of the CCCW system resulted in pH levels in three closed cooling subsystem below the specification limit. The applicant stated that chemistry recommendations were initi;3ted to add sodium hydroxide to increase pH. The applicant further stated that follow-up testing showed the pH returned to acceptable levels and that there has been no occurrence of the CCCW system chemistry sample results being out of specification since 2003. In addition to these examples, the staff reviewed the applicant's operating experience discussion provided in the applicant's license renewal program basis document binder for the Closed-Cycle Cooling Water System Program. The staff reviewed additional selected corrective Action Reports related to the Closed-Cycle Cooling Water System Program and interviewed the applicant's 3-54 technical staff to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. Based on its review, the staff finds (1) that the operating experience for this program demonstrates that the applicant's Closed-Cycle Cooling Water System Program is achieving its objective of managing the aging effects of loss of material and/or reduction in heat transfer for piping, piping components, piping elements and heat exchangers that are within the scope of license renewal and exposed to a closed cooling water environment; and (2) that the applicant is taking appropriate corrective actions through implementation of this program.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. LRA Section A.2.1.10 provides the applicant's UFSAR Supplement for the Closed-Cycle Cooling Water System Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staffs recommended UFSAR Supplement guidance found in the SRP-LR.In LRA Section A.5, Commitment No. 10, the applicant committed to credit the program for aging management of applicable components during the period of extended operation and also committed to the enhancement regarding the addition of a one-time inspection of selected CCCW components into the program.The staff finds that the applicant has provided an adequate summary description of the Closed-Cycle Cooling Water System Program as required by 10 CFR 54.21(d).Conclusion. On the basis of its review of the applicant's Closed-Cycle Cooling Water System program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exception and its justification andfinds that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. Also, the staff reviewed the enhancement and confirms that with its implementation through Commitment No. 10 prior to the period of extended operation, the existing program will be consistent with the GALL AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMPand concludes that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d).3.0.3.2.7 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Summary of Technical Information in the Application. LRA Section B.2.1.11 describes the existing Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program as being consistent, with enhancements, to GALL AMP XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems." The applicant stated that the program utilizes periodic visual inspections to Manage aging effects for structural components of cranes and hoists including the bridge, trolley, rail system, structural 3-55 technical staff to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. Based on its review, the staff finds (1) that the operating experience for this program demonstrates that the applicant's Closed-Cycle Cooling Water System Program is achieving its objective of managing the aging effects of loss of material and/or reduction in heat transfer for piping, piping components, piping elements and heat exchangers that are within the scope of license renewal and exposed to a closed cooling water environment; and (2) that the applicant is taking appropriate corrective actions through implementation of this program. The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1 O. The staff finds this program element acceptable. UFSAR Supplement. LRA Section A.2.1.10 provides the applicant's UFSAR Supplement for the Closed-Cycle Cooling Water System Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR. In LRA Section A.5, Commitment No. 10, the applicant committed to credit the program for aging management of applicable components during the period of extended operation and also committed to the enhancement regarding the addition of a one-time inspection of selected CCCW components into the program. The staff finds that the applicant has provided an adequate summary description of the Cycle Cooling Water System Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's Closed-Cycle Cooling Water System program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exception and its justification and finds that the AMP, with the exception, is adequate to manage the aging for which the LRA credits it. Also, the staff reviewed the enhancement and confirms that with its implementation through Commitment No. 10 prior to the period of extended operation, the existing program will be consistent with the GALL AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d). 3.0.3.2.7 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Summary of Technical Information in the Application. LRA Section B.2.1.11 describes the existing Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program as being consistent, with enhancements, to GALL AMP XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems." The applicant stated that the program utilizes periodiC visual inspections to manage aging effects for structural components of cranes and hoists including the bridge, trOlley, rail system, structural 3-55 bolting, and lifting devices in accordance with the provisions of NUREG-0612, "Control of Heavy Loads at Nuclear Power Plants." Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the enhancements to determine whether the AMP, with the enhancements, is adequate to manage the aging effects for which the LRA credits it.In comparing the elements in the applicant's program to those in GALL AMP XI.M23, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. The enhancements include guidance requiring the visual inspection of rails for loss of material due to wear, structural bolts for loss of material due to general corrosion, and evaluation of significant loss of material due to wear of the rail.Through its onsite review and discussions with the applicant, the staff noted that the program is implemented through procedures that are based on NRC approved guidance. Inspections are visual in nature, and are conducted on a routine basis for degradation, including annually for the reactor building crane and refueling platform, and bi-annually for diesel generator bridge cranes.Some more infrequently used cranes have an inspection frequency of either two years, or inspection prior to use.Enhancement

1. The LRA states an enhancement to the GALL Report as follows:The program will be enhanced to require visual inspection of the rails in the rail system for loss of material due to wear.By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program" and "parameters monitored/inspected" program elements.The staff finds this enhancement acceptable because when implemented, the Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems Program will be consistent with GALL AMP XI.M23 and will add assurance of adequate management of aging effects.Enhancement

2. The LRA states an enhancement to the GALL Report as follows: The program will be enhanced to require visual inspection of structural bolts for loss of material due to general corrosion.

By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program" and "parameters monitored/inspected" program elements.The staff finds this enhancement acceptable because when implemented, the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program will be consistent with GALL AMP XI.M23 and will add assurance of adequate management of aging effects.3-56 bolting, and lifting devices in accordance with the provisions of NUREG-0612, "Control of Heavy Loads at Nuclear Power Plants." Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the enhancements to determine whether the AMP, with the enhancements, is adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in GALL AMP XI.M23, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. The enhancements include guidance requiring the visual inspection of rails for loss of material due to wear, structural bolts for loss of material due to general corrosion, and evaluation of significant loss of material due to wear of the rail. Through its onsite review and discussions with the applicant, the staff noted that the program is implemented through procedures that are based on NRC approved guidance. Inspections are visual in nature, and are conducted on a routine basis for degradation, including annually for the reactor building crane and refueling platform, and bi-annually for diesel generator bridge cranes. Some more infrequently used cranes have an inspection frequency of either two years, or inspection prior to use. Enhancement

1. The LRA states an enhancement to the GALL Report as follows: The program will be enhanced to require visual inspection of the rails in the rail system for loss of material due to wear. By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program" and "parameters monitored/inspected" program elements.

The staff finds this enhancement acceptable because when implemented, the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program will be consistent with GALL AMP XI.M23 and will add assurance of adequate management of aging effects. Enhancement

2. The LRA states an enhancement to the GALL Report as follows: The program will be enhanced to require visual inspection of structural bolts for loss of material due to general corrosion.

By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program" and "parameters monitored/inspected" program elements. The staff finds this enhancement acceptable because when implemented, the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program will be consistent with GALL AMP XI.M23 and will add. assurance of adequate management of aging effects. ' 3-56 Enhancement

3. The LRA states an enhancement to the GALL Report as follows: Acceptance criteria will be enhanced to require evaluation of significant loss of material due to wear of the rail in the rail system.By letter dated October 30, 2008, the applicant stated that this enhancement applies to the"acceptance criteria" program element.The staff finds this enhancement acceptable because when implemented, the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program will be consistent with GALL AMP XI.M23 and will add assurance of adequate management of aging effects.Operatinq Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.11 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant stated that a review of approximately 400 corrective action reports did not identify any history of loss of material due to corrosion in cranes or in hoist's structural members, or loss of material due to wear in the rail system. The staff reviewed the operating experience reports, including a sample of issue reports, to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience.

In one report, the applicant stated that an event occurred in 2003, where cracks were discovered in 5 out of 16 pairs of diagonal braces on the reactor building polar crane. The applicant further stated that an engineering evaluation determined the diagonal braces were not needed for normal polar crane operation. The staff asked the applicant whether the diagonal braces would be needed for the planned steam generator replacement in 2009. The applicant responded to the question and stated thatthe reactor building polar crane will not be used for movement of the steam generators and that an auxiliary crane will be installed, partially supported by the polar crane rails, for movement of the steam generators. The staff reviewed the engineering evaluation for the auxiliary crane and finds it acceptable. 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. LRA section A.2.1.11 provides the applicant's UFSAR Supplement for the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staffs recommended UFSAR Supplement guidance found in the SRP-LR.In LRA Section A.5, commitment No. 11 the applicant committed to credit the program for aging management during the period of extended operation and also committed to the program enhancements related to the visual inspection of rails and structural bolting for loss of material prior to the period of extended operation. 3-57 Enhancement

3. The LRA states an enhancement to the GALL Report as follows: Acceptance criteria will be enhanced to require evaluation of significant loss of material due to wear of the rail in the rail system. By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "acceptance criteria" program element. The staff finds this enhancement acceptable because when implemented, the Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems Program will be consistent with GALL AMP XI.M23 and will add assurance of adequate management of aging effects. Operating Experience; The staff reviewed the operating experience provided in LRA Section B.2.1.11 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The applicant stated that a review of approximately 400 corrective action reports did not identify any history of loss of material due to corrosion in cranes or in hoist's structural members, or loss of material due to wear in the rail system. The staff reviewed the operating experience reports, including a sample of issue reports, to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. In one report, the applicant stated that an event occurred in 2003, where cracks were discovered in 5 out of 16 pairs of diagonal braces on the reactor building polar crane. The applicant further stated that an engineering evaluation determined the diagonal braces were not needed for normal polar crane operation. The staff asked the applicant whether the diagonal braces would be needed for the planned steam generator replacement in 2009. The applicant responded to the question and stated that the reactor building polar crane will not be used for movement of the steam generators and that an auxiliary crane will be installed, partially supported by the polar crane rails, for movement of the steam generators. The staff reviewed the engineering evaluation for the auxiliary crane and finds it acceptable. The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A1.2.3.1 O. The staff finds this program element acceptable. UFSAR Supplement. LRA section A2.1.11 provides the applicant's UFSAR Supplement for the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR. In LRA Section AS, commitment No. 11 the applicant committed to credit the program for aging management during the period of extended operation and also committed to the program enhancements related to the visual inspection of rails and structural bolting for loss of material prior to the period of extended operation. 3-57 The staff finds that the applicant has provided an adequate summary description of the Inspection of Overhead Heavy Load and Light Load (Related to-Refueling) Handling Systems Program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program the staff finds that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. The staff reviewed the enhancements and related justification and finds that with their implementation through Commitment No. 11 prior to the period of extended operation, the existing program will be consistent with the GALL AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program, as required by 10 CFR 54.21 (d).3.0.3.2.8 Compressed Air Monitoring Summary of Technical Information in the Application. LRA Section B.2.1.12 describes the existing Compressed Air Monitoring Program as being consistent, with enhancements, with GALL AMP XI.M24, "Compressed Air Monitoring." The applicant stated that this program provides for managing the internal surfaces of piping and components in a compressed air system for loss of material due to general, pitting and crevice corrosion, and the reduction of heat transfer due to fouling.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the enhancements to determine whether the applicant's program, with the enhancements is adequate to manage the aging effects for which the LRA credits it.In comparing the elements in the applicant's program to those in GALL AMP XI.M24, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent, but several issues were identified for which the staff requested additional information. GALL AMP XI.M24 states that the program manages the effects of corrosion and presence of unacceptable levels of contaminants on the intended function of the compressed air system. LRA Section B.2.1.12 states that the program manages loss of material due to corrosion and reduction of heat transfer due to fouling. In RAI B.2.1.12-1, dated September 29, 2008, the staff requested that the applicant provide additional information to explain how this program manages the effects of fouling and the resulting reduction of heat transfer.In its response to the RAI dated October 20, 2008, the applicant stated that during the maintenance that is performed on instrument air aftercoolers every four years, the aftercoolers are disassembled and inspected for a number of attributes including: corrosion, scaling, slime or other coating of the tubes, the presence of silt or debris, and other forms of fouling. The applicant stated that if discrepancies are identified, then Issue Reports are initiated and corrective actions are taken.3-58 The staff finds that the applicant has provided an adequate summary description of the Inspection of Overhead Heavy Load and Light Load (Related toRefueling) Handling Systems Program, as required by 10 CFR 54.21 (d). Conclusion. On the basis of its audit and review of the applicant's Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program the staff finds that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. The staff reviewed the enhancements and related justification and finds that with their implementation through Commitment No. 11 prior to the period of extended operation, the existing program will be consistent with the GALL AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that intended function( s) will be maintained consistent with the CLB for the period of extended ' operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program, as required by 10 CFR 54.21 (d). 3.0.3.2.8 Compressed Air Monitoring Summary of Technical Information in the Application. LRA Section B.2.1.12 describes the existing Compressed Air Monitoring Program as being consistent, with enhancements, with GALL AMP XI.M24, "Compressed Air Monitoring." The applicant stated that this program provides for managing the internal surfaces of piping and components in a compressed air system for loss of material due to general, pitting and crevice corrosion, and the reduction of heat transfer due to fouling. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the enhancements to determine whether the applicant's program, with the enhancements is adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in GALL AMP XI.M24, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent, but several issues were identified for which the staff requested additional information. GALL AMP XI.M24 states. that the program manages the effects of corrosion and presence of unacceptable levels of contaminants on the intended function of the compressed air system. LRA Section B.2.1.12 states that the program manages loss of material due to corrosion and reduction of heat transfer due to fouling. In RAI B.2.1.12-1, dated September 29, 2008, the staff requested that the applicant provide additional information to explain how this program manages the effects of fouling and the resulting reduction of heat transfer. In its response to the RAI dated October 20, 2008, the applicant stated that during the maintenance that is performed on instrument air aftercoolers every four years, the aftercoolers are disassembled and inspected for a number of attributes including: corrosion, scaling, slime or other coating of the tubes, the presence of silt or debris, and other forms of fouling. The applicant stated that if discrepancies are identified, then Issue Reports are initiated and corrective actions are taken. 3-58 Based on its review, the staff finds the applicant's response to RAI B.2.1.12-1 acceptable because the applicant stated that they visually inspect for fouling caused by silt, debris, and slime during the periodic disassembly and inspection of the aftercoolers. The staff confirmed that during disassembly, the internals of the aftercoolers are accessible and can be visually inspected and any fouling would be observed and identified for further corrective actions. The staff's concern described in RAI B.2.1.12-1 is resolved.GALL AMP XI.M24, in the "monitoring and trending" program element states that test data is analyzed and compared to data from previous tests to provide for timely detection of aging effects. The applicant's program basis document for this program element stated that results of tests are compared to established acceptance criteria; however, it is not clear to the staff if these results are compared to previous test results to establish a trend. In RAI B.2.1.12-2, dated September 29, 2008, the staff requested that the applicant provide additional information to clarify this issue and discuss if the test results are also compared to previous test results for trending purposes.In its response to the RAI dated October 20, 2008, the applicant stated that its Conduct of Plant Engineering Manual requires the system manager to maintain a system notebook that contains current and historical performance data, and analysis results, which are used by the system manager to trend the previous data along with the current data to identify any adverse trends or reductions in margin that may be indicative of aging.Based on its review, the staff finds the applicant's response to RAI B.2.1.12-2 acceptable because the applicant states that they compare previous results to establish any adverse trends or reductions in margin that may be indicative of aging. Additionally, the staff noted that this comparison to historical results is performed for all systems, including the compressed air system.The staffs concern described in RAI B.2.1.12-2 is resolved.Enhancement

1. The LRA states an enhancement to the GALL Report as follows: The Compressed Air Monitoring program will be enhanced to include instrument air system air quality testing for dew point, particulates, lubricant content, and contaminants to ensure that the contamination standards of ANSI/ISA-S7.0.01-1996, paragraph 5 are met. These enhancements will be made to the existing program GL 88-14 Instrument Air Program.By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program," "preventive actions," and "parameters monitored/inspected," program elements.GALL AMP XI.M24 states that system air quality is monitored and maintained in accordance with plant owners testing plans, which are prepared from guidelines based on industry standards.

One of the industry standards identified in the GALL AMP is ISA-S7.0.01-1996. Based on its review, the staff finds this enhancement to be acceptable because when implemented, it will make the Compressed Air Monitoring Program consistent with the GALL Report.Enhancement

2. The LRA states an enhancement to the GALL Report as follows: In addition the Compressed Air Monitoring program will be enhanced to include air sampling activities on a representative sampling of headers on a yearly basis in accordance with ASME OM-S/G-1 998, Part 17 and EPRI TR-1 08147.3-59 Based on its review, the staff finds the applicant's response to RAI B.2.1.12-1 acceptable because the applicant stated that they visually inspect for fouling caused by silt, debris, and slime during the periodic disassembly and inspection of the aftercoolers.

The staff confirmed that during disassembly, the internals of the aftercoolers are accessible and can be visually inspected and any fouling would be observed and identified for further corrective actions. The staff's concern described in RAI B.2.1.12-1 is resolved. GALL AMP XI.M24, in the "monitoring and trending" program element states that test data is analyzed and compared to data from previous tests to provide for timely detection of aging effects. The applicant's program basis document for this program element stated that results of tests are compared to established acceptance criteria; however, it is not clear to the staff if these results are compared to previous test results to establish a trend. In RAI B.2.1.12-2, dated September 29, 2008, the staff requested that the applicant provide additional information to clarify this issue and discuss if the test results are also compared to previous test results for trending purposes. In its response to the RAI dated October 20, 2008, the applicant stated that its Conduct of Plant Engineering Manual requires the system manager to maintain a system notebook that contains current and historical performance data, and analysis results, which are used by the system manager to trend the previous data along with the current data to identify any adverse trends or reductions in margin that may be indicative of aging. Based on its review, the staff finds the applicant's response to RAI B.2.1.12-2 acceptable because the applicant states that they compare previous results to establish any adverse trends or reductions in margin that may be indicative of aging. Additionally, the staff noted that this comparison to historical results is performed for all systems, including the compressed air system. The staff's concern described in RAI B.2.1.12-2 is resolved. Enhancement

1. The LRA states an enhancement to the GALL Report as follows: The Compressed Air Monitoring program will be enhanced to include instrument air system air quality testing for dew point, particulates, lubricant content, and contaminants to ensure that the contamination standards of ANSIIISA-S7.0.01-1996, paragraph 5 are met. These enhancements will be made to the existing program GL 88-14 Instrument Air Program. By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program," "preventive actions," and "parameters monitored/inspected," program elements.

GALL AMP XI.M24 states that system air quality is monitored and maintained in accordance with plant owners testing plans, which are prepared from guidelines based on industry standards. One of the industry standards identified in the GALL AMP is ISA-S7.0.01-1996. Based on its review, the staff finds this enhancement to be acceptable because when implemented, it will make the Compressed Air Monitoring Program consistent with the GALL Report. Enhancement

2. The LRA states an enhancement to the GALL Report as follows: In addition the Compressed Air Monitoring program will be enhanced to include air sampling activities on a representative sampling of headers on a yearly basis in accordance with ASME OM-S/G-1998, Part 17 and EPRI TR-108147.

3-59 By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program," "preventive actions," and, "detection of aging effects," program elements.GALL Report AMP XI.M24 states that guidelines in EPRI TR-1 08147 and ASME OM-S/G-1998, Part 17, ensure timely detection of degradation of the compressed air system function.Based on its review, the staff finds this enhancement acceptable because when implemented, it will make the Compressed Air Monitoring Program consistent with the GALL Report.Operatinq Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.12 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant stated that the performance of air dryers is actively monitored and maintained within acceptance criteria as evidenced by system reports initiated between April and June 2004, and that when the instrument air quality is not within acceptance limits, corrective actions are immediately taken to resolve the condition. The applicant also stated that examples of leakage in the instrument air system were reported in several Issue Reports initiated from April 2002 to October 2003, and appropriate corrective actions were implemented in each case.The staff reviewed issue reports as part of the operating experience review during the audit and found that the applicant had identified degradation in an instrument air dryer and identified a failed transmitter on an instrument air dryer. The applicant had taken appropriate corrective actions in each case to resolve the issues.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 the program element acceptable. UFSAR Supplement. In LRA Section A.2.1.12, the applicant provided the UFSAR Supplement for the Compressed Air Monitoring Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement for this type of program as found in SRP-LR Table 3.3-2.In LRA Section A.5, Commitment No. 12, the applicant committed to the enhancements regarding instrument air system air quality testing for dew point, particulates, lubricant content, and contaminants; and air sampling activities on a representative sampling of headers on a yearly basis, prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Compressed Air Monitoring Program in the UFSAR Supplement as required by 10 CFR 54.21(d).Conclusion. On the basis of its audit and review of the applicant's Compressed Air Monitoring Program, and the applicant's response to the RAIs, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that their implementation through Commitment No. 12 prior to the period of extended operation will make the existing AMP consistent with GALL AMP XI.M24. The staff concludes that the applicant has demonstrated that the effects of aging will be 3-60 By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program," "preventive actions," and, "detection of aging effects," program elements. GALL Report AMP XI.M24 states that guidelines in EPRI TR-108147 and ASME OM-S/G-1998, Part 17, ensure timely detection of degradation of the compressed air system function. Based on its review, the staff finds this enhancement acceptable because when implemented, it will make the Compressed Air Monitoring Program consistent with the GALL Report. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.12 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The applicant stated that the performance of air dryers is actively monitored and maintained within acceptance criteria as evidenced by system reports initiated between April and June 2004, and that when the instrument air quality is not within acceptance limits, corrective actions are immediately taken to resolve the condition. The applicant also stated that examples of leakage in the instrument air system were reported in several Issue Reports initiated from April 2002 to October 2003, and appropriate corrective actions were implemented in each case. The staff reviewed issue reports as part of the operating experience review during the audit and found that the applicant had identified degradation in an instrument air dryer and identified a failed transmitter on an instrument air dryer. The applicant had taken appropriate corrective actions in each case to resolve the issues. Tt.:le staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A1.2.3.1 O. The staff finds the program element acceptable. UFSAR Supplement. In LRA Section A2.1.12, the applicant provided the UFSAR Supplement for the Compressed Air Monitoring Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement for this type of program as found in SRP-LR Table 3.3-2. In LRA Section A5, Commitment No. 12, the applicant committed to the enhancements regarding instrument air system air quality testing for dew point, particulates, lubricant content, and contaminants; and air sampling activities on a representative sampling of headers on a yearly basis, prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Compressed Air Monitoring Program in the UFSAR Supplement as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Compressed Air Monitoring Program, and the applicant's response to the RAls, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that their implementation through Commitment No. 12 prior to the period of extended operation will make the existing AMP consistent with GALL AMP XI.M24. The staff concludes that the applicant has demonstrated that the effects of aging will be 3-60 adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes the applicant has provided an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.9 Fire Protection Summary of Technical Information in the Application. LRA Section B.2.1.13 describes the existing Fire Protection Program as being consistent with an exception, and enhancements, with GALL AMP XI.M26, "Fire Protection." The applicant stated that this program provides for visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, and fire doors; periodic surveillance testing of fuel oil lines for the diesel driven fire pumps; and visual inspection of external surfaces of halon and carbon dioxide (C0 2) fire suppression system components. The applicant stated that this program manages the aging effects of change in material properties, cracking, hardening and loss of material.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception and the enhancements todetermine whether the program, with the exception and enhancements, is adequate to manage the aging effects for which the LRA credits it.In comparing the elements in the applicant's program to those in GALL AMP XI.M26, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. The staff identified issues with the "detection of aging effects" program element and the "acceptance criteria" program element for which the staff requested additional information. The "detection of aging effects" program element of GALL AMP XI.M26, states that visual inspections of halon/C0 2 systems detects any sign of degradation, such as corrosion, mechanical damage, or damage to dampers. The applicant's program basis document references plant surveillance procedures that do not clearly state that systems should be inspected for corrosion, mechanical damage or damage to dampers. In RAI B.2.1.13-1, dated September 29, 2008, the staff requested that the applicant provide additional information regarding the basis for not providing an enhancement to the program to provide for these inspections. The "acceptance criteria" program element of GALL AMP XI.M26, states any signs of corrosion and mechanical damage of the halon/C0 2 fire suppression system are not acceptable. The staff determined that there is no acceptance criteria specified for the inspection parameters in the surveillance procedures that are referenced in the program basis document for halon/carbon dioxide systems. In RAI B.2.1.13-2, dated September 29, 2008, the staff requested that the applicant provide additional information as to why there was not an enhancement to the programto provide for the acceptance criteria for the inspection of these system components. In its response to the RAI dated October 20, 2008, the applicant stated that the program basis document directs halon and C02 fire suppression system surveillance that verifies system operation including associated dampers, and identifies adverse conditions such as corrosion, broken or missing parts, loose fasteners, excessive dirt or debris, or other degrading condition forcorrective action evaluation. The applicant further stated that although the halon system andCO 2 system implementing surveillance procedures require that conditions that could adversely affect 3-61 adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes the applicant has provided an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.9 Fire Protection Summary of Technical Information in the Application. LRA Section B.2.1.13 describes the existing Fire Protection Program as being consistent with an exception, and enhancements, with GALL AMP XI,M26, "Fire Protection." The applicant stated that this program provides for visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, and fire doors; periodic surveillance testing of fuel oil lines for the diesel driven fire pumps; and visual inspection of external surfaces of halon and carbon dioxide (C0 2) fire suppression system components. The applicant stated that this program manages the aging effects of change in material properties, cracking, hardening and loss of material. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception and the enhancements to determine whether the program, with the exception and enhancements, is adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in GALL AMP XI,M26, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. The staff identified issues with the "detection of aging effects" program element and the "acceptance criteria" program element for which the staff requested additional information. The "detection of aging effects" program element of GALL AMP XI,M26, states that visual inspections of halon/C0 2 systems detects any sign of degradation, such as corrosion, mechanical damage, or damage to dampers. The applicant's program basis document references plant surveillance procedures that do not clearly state that systems should be inspected for corrosion, mechanical damage or damage to dampers. In RAI B.2.1.13-1, dated September 29, 2008, the staff requested that the applicant provide additional information regarding the basis for not providing an enhancement to the program to provide for these inspections. The "acceptance criteria" program element of GALL AMP XI,M26, states any signs of corrosion and mechanical damage of the halon/C0 2 fire suppression system are not acceptable. The staff determined that there is no acceptance criteria specified for the inspection parameters in the' surveillance procedures that are referenced in the program basis document for halon/carbon dioxide systems. In RAI B.2.1.13-2, dated September 29, 2008, the staff requested that the applicant provide additional information as to why there was not an enhancement to the program to provide for the acceptance criteria for the inspection of these system components. In its response to the RAI dated October 20, 2008, the applicant stated that the program basis document directs halon and CO 2 fire suppression system surveillance that verifies system operation including associated dampers, and identifies adverse conditions such as corrosion, broken or missing parts, loose fasteners, excessive dirt or debris, or other degrading' condition for corrective action evaluation. The applicant further stated that although the halon system and,C0 2 system implementing surveillance procedures require that conditions that could adversely affect 3-61 equipment operation such as those stated in the program basis document be identified for evaluation, these procedures will be enhanced with clarifying reinforcement assuring inspection specifically for the GALL Report aging mechanisms of corrosion, mechanical damage or damage to dampers.In its response to the RAI dated October 20, 2008, the applicant stated that the "limits and precautions" sections of these implementing procedures currently state that detection of any of these conditions require evaluation for corrective action. The applicant further stated that these procedures will be clarified to state specifically that that the results of inspection for corrosion and mechanical damage be evaluated, with corrective action taken as appropriate. The applicant also stated that these clarifications to be added to the implementing procedures are not considered enhancements to the program because the program currently directs inspection ofany adverse conditions such as corrosion, broken or missing parts, loose fasteners, excessive dirt or debris, or other degrading condition. However, as a result of these clarifying additions, the applicant revised LRA, Appendix A, Table A.5, Commitment No. 13, by adding the following statement: In addition, implementing surveillance procedures for Halon and C02 suppression systems will specifically require inspection for corrosion, mechanical damage, or damage to dampers, and will include acceptance criteria stating that detected signs of corrosion or mechanical damage be evaluated, with corrective action taken as appropriate. Based on its review, the staff finds the applicant's responses to RAIs B.2.1.13-1 and B.2.1.13-2 acceptable because the program basis document includes inspection for corrosion and mechanical damage and also finds that enhancements to the program are not necessary. The staff also finds that the revision to Commitment No.13 to revise the implementing procedures to specifically include these inspections and acceptance criteria is acceptable, because these revisions will make the applicant's program consistent with GALL AMP XI.M26. The staffs concerns discussed in RAls B.2.1.13-1 and B.2.1.13-2 are resolved.Exception. The LRA states an exception to the GALL Report as follows: NUREG-1801 recommends visual inspection and functional testing of the halon and C02 fire suppression systems at least once every six months. Procedurally, the TMI-1 halon fire suppression system currently undergoes operational testing and inspections every 18 months, and the TMI-1 low pressure CO 2 fire suppression system undergoes operational testing and inspections every 24 months. Additionally, the halon fire suppression system undergoes more frequent Visual inspections for system charge (storage tank pressure at least every 3 months, and storage tank weight at least every 6 months), and the low-pressure carbon dioxide fire suppression system undergoes a visual storage tank level and pressure check at least weekly. These test frequencies are considered sufficient to ensure system availability and operability based on the station's operating history that shows no aging related events that have adversely affected system operation. Similar exceptions to the NUREG-1 801 recommended frequency for periodic function test of the halon and C02 fire suppression systems were previously approved by the NRC in NUREG-1 796, Safety Evaluation Report Related to the License Renewal of the Dresden Nuclear Power Station, Units 2 and 3 and Quad Cities Nuclear Power Station, Units 1 and 2, and in NUREG-1875, Safety Evaluation Report Related to the License Renewal ofOyster Creek Generating Station. In each case for these plants, periodic functional testing 3-62 equipment operation such as those stated in the program basis document be identified for evaluation, these procedures will be enhanced with clarifying reinforcement assuring inspection specifically for the GALL Report aging mechanisms of corrosion, mechanical damage or damage to dampers. In its response to the RAI dated October 20, 2008, the applicant stated that the "limits and precautions" sections of these implementing procedures currently state that detection of any of these conditions require evaluation for corrective action. The applicant further stated that these procedures will be clarified to state specifically that that the results of inspection for corrosion and mechanical damage be evaluated, with corrective action taken as appropriate. The applicant also stated that these clarifications to be added to the implementing procedures are not considered enhancements to the program because the program currently directs inspection of any adverse conditions such as corrosion, broken or missing parts, loose fasteners, excessive dirt or debris, or other degrading condition. However, as a result of these clarifying additions, the applicant revised LRA, Appendix A, Table A.5, Commitment No. 13, by adding the following statement: In addition, implementing surveillance procedures for Halon and CO 2 suppression systems will specifically require inspection for corrosion, mechanical damage, or damage to dampers, and will include acceptance criteria stating that detected signs of corrosion or mechanical damage be evaluated, with corrective action taken as appropriate. 8ased on its review, the staff finds the applicant's responses to RAls 8.2.1.13-1 and 8.2.1.13-2 acceptable because the program basis document includes inspection for corrosion and mechanical damage and also finds that enhancements to the program are not necessary. The staff also finds that the revision to Commitment No.13 to revise the implementing procedures to specifically include these inspections and acceptance criteria is acceptable, because these revisions will make the applicant's program consistent with GALL AMP XI.M26. The staff's concerns discussed in RAls 8.2.1.13-1 and 8.2.1.13-2 are resolved. Exception. The LRA states an exception to the GALL Report as follows: NUREG-1801 recommends visual inspection and functional testing of the halon and CO 2 fire suppression systems at least once every six months. Procedurally, the TMI-1 halon fire suppression system currently undergoes operational testing and inspections every 18 months, and the TMI-1 low pressure CO 2 fire suppression system undergoes operational testing and inspections every 24 months. Additionally, the halon fire suppression system undergoes more frequent visual inspections for system charge (storage tank pressure at least every 3 months, and storage tank weight at least every 6 months), and the pressure carbon dioxide fire suppression system undergoes a visual storage tank level and pressure check at least weekly. These test frequencies are considered sufficient to ensure system availability and operability based on the station's operating history that shows no aging related events that have adversely affected system operation. Similar exceptions to the NUREG-1801 recommended frequency for periodic function test of the halon and CO 2 fire suppression systems were previously approved by the NRC in NUREG-1796, Safety Evaluation Report Related to the License Renewal of the Dresden Nuclear Power Station, Units 2 and 3 and Quad Cities Nuclear Power Station, Units 1 and 2, and in NUREG-1875, Safety Evaluation Report Related to the License Renewal of Oyster Creek Generating Station. In each case for these plants, periodic functional testing 3-62 of the halon and CO 2 fire suppression systems is currently performed every 18 months.(Additionally, for Dresden and Quad Cities, the Technical Requirements Manual permits a testing frequency of once every two years.) The NRC staff found that on the basis of plant experience, the testing frequency was adequate for aging management considerations. For these plants, as for TMI- 1, station operating history indicated that there were no occurrences of aging related events having adversely affected system operation. A review of the functional surveillance tests performed for the TMI-1 halon and CO 2 systems within the last five years confirmed that there have been no occurrences of aging related events that adversely affected either system's operation. The December 2006 halon system functional test was completed with all steps satisfactory after an evaluation of a repeated switch actuation required for multiple fan start determined that the switch had not been manually operated properly for the test. No occurrence of any aging related degradation having adversely affected the system's operation was observed.The June 2005 halon system functional was completed with all steps satisfactory. No occurrence of any aging related degradation having adversely affected the system's operation was observed. During the February 2004 halon system functional test, a fan motor failed and required replacement, and a valve limit switch required adjustment to properly indicate the associated valve was fully open. No occurrence of any aging related degradation of passive components having adversely affected the system's operation was observed.The November 2005 CO 2 system functional test was completed with all steps satisfactory. Although an evaluation determined that a damaged fire damper grill was redundant and did not require replacement, the primary grill for the damper is functional for foreign material exclusion and the damper and system are operable. No occurrence of any degradation of passive components due to aging having adversely affected the system's operation was observed. During the November 2003 CO 2 system functional test, an electro-thermal link did not fully melt, causing a damper to not fully close. The link was replaced and the test re-performed satisfactorily. A CO 2 tank level was found low due to performance of a test and was subsequently re-filled. No occurrence of any aging related degradation having adversely affected the system's operation was observed. The October 2001 CO 2 system functional test was competed with all steps satisfactory. No occurrence of any aging related degradation having adversely affected the system's operation was observed.On the basis of TMI-1 plant experience that no occurrence of any aging related degradation having adversely affected either the halon or the CO 2 systems' operation has been observed, the test frequencies are considered sufficient to ensure system availability and operability, and are adequate for aging management considerations. By letter dated October 30, 2008, the applicant stated that this exception applies to the"parameters monitored/inspected," and "detection of aging effects," program elements.The staff reviewed the applicant's program basis document and the CLB, including the UFSAR and the Technical Requirements Manual, and noted that the frequencies for halon/carbon dioxide system tests are as identified in the LRA Section B.2.1.13. The staff also reviewed the applicant's operating experience report and did not find any age related degradation in the halon/carbon dioxide systems.Based on its review, the staff finds the exception to the GALL Report acceptable because the applicant is (1) performing functional tests in accordance with its CLB, (2) performing more 3-63 of the halon and CO 2 fire suppression systems is currently performed every 18 months. (Additionally, for Dresden and Quad Cities, the Technical Requirements Manual permits a testing frequency of once every two years.) The NRC staff found that on the basis of plant experience, the testing frequency was adequate for aging management considerations. For these plants, as for TMI-1, station operating history indicated that there were no occurrences of aging related events having adversely affected system operation. A review of the functional surveillance tests performed for the TMI-1 halon and CO 2 systems within the last five years confirmed that there have been no occurrences of aging related events that adversely affected either system's operation. The December 2006 halon system functional test was completed with all steps satisfactory after an evaluation of a repeated switch actuation required for multiple fan start determined that the switch had not been manually operated properly for the test. No occurrence of any aging related degradation having adversely affected the system's operation was observed. The June 2005 halon system functional was completed with all steps satisfactory. No. occurrence of any aging related degradation having adversely affected the system's operation was observed. During the February 2004 halon system functional test, a fan motor failed and required replacement, and a valve limit switch required adjustment to properly indicate the associated valve was fully open. No occurrence of any aging related degradation of passive components having adversely affected the system's operation was observed. The November 2005 CO 2 system functional test was completed with all steps satisfactory. Although an evaluation determined that a damaged fire damper grill was redundant and did not require replacement, the primary grill for the damper is functional for foreign material exclusion and the damper and system are operable. No occurrence of any degradation of passive components due to aging having adversely affected the system's operation was observed. During the November 2003 CO 2 system functional test, an electro-thermal link did not fully melt, causing a damper to not fully close. The link was replaced and the test re-performed satisfactorily. A CO 2 tank level was found low due to performance of a test and was subsequently re-filled. No occurrence of any aging related degradation having adversely affected the system's operation was observed. The October 2001 CO 2 system functional test was competed with all steps satisfactory. No occurrence of any aging related degradation having adversely affected the system's operation was observed. On the basis of TMI-1 plant experience that no occurrence of any aging related degradation having adversely affected either the halon or the CO 2 systems' operation has been observed, the test frequencies are considered sufficient to ensure system availability and operability, and are adequate for aging management considerations. By letter dated October 30, 2008, the applicant stated that this exception applies to the "parameters monitored/inspected," and "detection of aging effects," program elements .. The staff reviewed the applicant's program basis document and the CLB, including the UFSAR and the Technical Requirements Manual, and noted that the frequencies for halon/carbon dioxide system tests are as identified in the LRA Section B.2.1.13. The staff also reviewed the applicant's operating experience report and did not find any age related degradation in the halon/carbon dioxide systems. Based on its review, the staff finds the exception to the GALL Report acceptable because the applicant is (1) performing functional tests in accordance with its CLB, (2) performing more 3-63 frequent visual inspections at intervals of every three to six months of the halon fire suppression system, (3) performing weekly visual inspections of carbon dioxide system storage tank level and pressure, and (4) based on the plant-specific operating experience, the staff finds that these inspection and testing frequencies are adequate to ensure the systems maintain their function.Enhancement

1. The LRA states an enhancement to the GALL Report as follows: The program will provide for additional inspection criteria for degradation of fire barrier walls, ceilings, and floors.By letter dated October 30, 2008, the applicant stated that this enhancement applies to the"parameters monitored/inspected," "detection of aging effects," "monitoring and trending," and"acceptance criteria" program elements.The "parameters monitored/inspected" program element of GALL AMP XI.M26, recommends that visual inspection of the fire barrier walls, ceilings, and floors examine any sign of degradation such as cracking, spalling, and loss of material caused by freeze-thaw, chemical attack, and reaction with aggregates.

Based on its review, the staff finds the applicant's enhancement acceptable because it will makethe applicant's program consistent with GALL AMP XI.M26.Enhancement

2. The LRA states an enhancement to the GALL Report as follows: The program will provide specific fuel supply line inspection criteria for diesel-driven fire pumps during tests.By letter dated October 30, 2008, the applicant stated that this enhancement applies to the"parameters monitored/inspected," "detection of aging effects," "monitoring and trending," and,"acceptance criteria" program elements.The "acceptance criteria" program element of GALL AMP XI.M26, recommends that no corrosion is acceptable in the fuel supply line for the diesel-driven fire pump. In its response to RAI B.2.1.13-1, the applicant stated that acceptance criteria will include a statement that detected signs of corrosion or mechanical damage be evaluated, with corrective action taken as appropriate.

Based on its review, the staff finds the applicant's enhancement acceptable because it will make the applicant's program consistent with GALL AMP XI.M26.Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.13 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The staff also reviewed the applicant's operating experience discussion that was provided in the applicant's license renewal basis document for the Fire Protection Program. The staff reviewed a 3-64 frequent visual inspections at intervals of every three to six months of the halon fire suppression system, (3) performing weekly visual inspections of carbon dioxide system storage tank level and pressure, and (4) based on the plant-specific operating experience, the staff finds that these inspection and testing frequencies are adequate to ensure the systems maintain their function. Enhancement

1. The LRA states an enhancement to the GALL Report as follows: The program will provide for additional inspection criteria for degradation of fire barrier walls, ceilings, and floors. By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "parameters monitored/inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements.

The "parameters monitored/inspected" program element of GALL AMP XI.M26, recommends that visual inspection of the fire barrier walls, ceilings, and floors examine any sign of degradation such as cracking, spalling, and loss of material caused by freeze-thaw, chemical attack, and reaction with aggregates. Based on its review, the staff finds the applicant's enhancement acceptable because it will make the applicant's program consistent with GALL AMP XI.M26. Enhancement

2. The LRA states an enhancement to the GALL Report as follows: The program will provide specific fuel supply line inspection criteria for diesel-driven fire pumps during tests. By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "parameters monitored/inspected," "detection of aging effects," "monitoring and trending," and, "acceptance criteria" program elements.

The "acceptance criteria" program element of GALL AMP XI.M26, recommends that no corrosion is acceptable in the fuel supply line for the diesel-driven fire pump. In its response to RAI B.2.1.13-1, the applicant stated that acceptance criteria will include a statement that detected signs of corrosion or mechanical damage be evaluated, with corrective action taken as appropriate. Based on its review, the staff finds the applicant's enhancement acceptable because it will make the applicant's program consistent with GALL AMP XI.M26. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.13 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The staff also reviewed the applicant's operating experience discussion that was provided in the applicant's license renewal basis document for the Fire Protection Program. The staff reviewed a 3-64 sample of issue reports and confirmed that the applicant had identified age related degradation and implemented appropriate corrective actions.The applicant provided several examples of its plant operating experience in LRA Section B.2.1.13 such as, degraded condition of fire door seal plate; repeated fire door latch failures;missing fasteners form metal plate closures on fire walls; and degraded seal in the floor of thecontrol room. In all cases, the applicant evaluated the extent of the problem and took appropriate corrective action, including repair and replacement. Furthermore, the staff confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The staff finds that the applicant's Fire Protection Program, with the corrective actions discussed in the LRA, has been effective in identifying, monitoring, and correcting the effects of age related degradation in fire protection system components and structures. The staff confirmed 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. LRA Section A.2.1.13 provides the applicant's UFSAR Supplement for the Fire Protection Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found the SRP-LR.In LRA Section A.5, Commitment No. 13, the applicant committed to the program enhancements related to the additional inspection criteria for degradation of fire barrier walls, ceilings, and floors;and the specific fuel supply line inspection criteria for diesel-driven fire pumps during tests prior to the period of extended operation. In a letter dated October 20, 2008, the applicant revised Commitment No. 13 to state that prior to the period of extended operation, implementing surveillance procedures for Halon and CO 2 suppression systems will specifically require inspection for corrosion, mechanical damage, or damage to dampers, and will include acceptance criteria stating that detected signs of corrosion or mechanical damage be evaluated, with corrective action taken as appropriate. The staff finds that the applicant has provided an adequate summary description of the Fire Protection Program as required by 10 CFR 54.21(d).Conclusion. On the basis of its audit and review of the applicant's Fire Protection Program, and the applicant's response to the RAIs, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. The staff reviewed the exception and its justification and finds that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. The staff also reviewed the enhancements and confirmed that their implementation through Commitment No. 13 prior to the period of extended operation will make the existing AMP consistent with the GALL AMP to which it was compared.The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3-65 sample of issue reports and confirmed that the applicant had identified age related degradation and implemented appropriate corrective actions. The applicant provided several examples of its plant operating experience in LRA Section B.2.1.13 such as, degraded condition of fire door seal plate; repeated fire door latch failures; missing fasteners form metal plate closures on fire walls; and degraded seal in the floor of the control room. In all cases, the applicant evaluated the extent of the problem and took appropriate corrective action, including repair and replacement. Furthermore, the staff confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The staff finds that the applicant's Fire Protection Program, with the corrective actions discussed in the LRA, has been effective in identifying, monitoring, and correcting the effects of age related degradation in fire protection system components and structures. The staff confirmed the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP LR Section A1.2.3.1 O. The staff finds this program element acceptable. UFSAR Supplement. LRA Section A2.1.13 provides the applicant's UFSAR Supplement for the Fire Protection Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found the SRP-LR. In LRA Section A5, Commitment No. 13, the applicant committed to the program enhancements related to the additional inspection criteria for degradation of fire barrier walls, ceilings, and floors; and the specific fuel supply line inspection criteria for diesel-driven fire pumps during tests prior to the period of extended operation. In a letter dated October 20, 2008, the applicant revised Commitment No. 13 to state that prior to the period of extended operation, implementing surveillance procedures for Halon and CO 2 suppression systems will specifically require inspection for corrosion, mechanical damage, or damage to dampers, and will include acceptance criteria stating that detected signs of corrosion or mechanical damage be evaluated, with corrective action taken as appropriate. The staff finds that the applicant has provided an adequate summary' description of the Fire Protection Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Fire Protection Program, and the applicant's response to the RAls, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report, are ,consistent. The staff reviewed the exception and its justification and finds that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. The staff also reviewed the enhancements and confirmed that their implementation through Commitment No. 13 prior to the period of extended operation will make the existing AMP consistent with the GALL AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3-65 3.0.3.2.10 Fire Water System Summary of Technical Information in the Application. LRA Section B.2.1.14 describes the existing Fire Water System Program as being consistent, with enhancements, with GALL AMP XI.M27,"Fire Water System." The applicant stated that this program manages aging effects for the water-based fire protectionsystem and associated components through the use of periodic inspections, monitoring, andperformance testing and provides for preventive measures and inspection activities to detect aging effects prior to loss of intended functions. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the enhancements to determine whether the program, with the enhancements, is adequate to manage the aging effects for which the LRA credits it.In comparing the elements in the applicant's program to those in GALL AMP XI.M27, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. The staff identified an issue with the "acceptance criteria" program element for which the staff requested additional information. The "acceptance criteria" program element of GALL AMP XI.M27, states that no biofouling exists in the sprinkler systems that could cause corrosion in the sprinkler heads. In the applicant's Fire Water System Program basis document, the applicant stated that new inspection activities will include an evaluation of identified fouling. During the audit, the applicant indicated that non-intrusive testing techniques such as ultrasonic testing will be used. In RAI B.2.1.14-1, dated September 29, 2008, the staff requested that the applicant provide additional information to clarify how the new ultrasonic examination activity will evaluate fouling.In its response to the RAI dated October 20, 2008, the applicant stated the following: The volumetric non-intrusive examination activities include an evaluation of identified degradation for impact on the system or component function. In accordance with the corrective action process for deficiencies determined to be significantly adverse to quality, the cause of the condition is determined. The aging effect of loss of material can be caused by the aging mechanism of fouling. Fouling would therefore be considered and evaluated as a potential cause of loss of material in fire water service piping. Volumetric examinations do not directly determine fouling as an aging mechanism; however, they provide evidence of the aging effect of loss of material that may result from the aging mechanism of fouling.Based on its review, the staff finds the applicant's response to RAI B.2.1.14-1 acceptable because the applicant is using a volumetric examination to detect loss of material, and the results would be evaluated by the corrective action process to determine the cause. The staff determines that one of the causes could be fouling in the sprinkler heads, which the applicant considers a potential cause for loss of material. The staff finds that the volumetric examination would detect fouling indirectly as a cause for corrosion and loss of material, and would therefore make the program consistent with the "acceptance criteria" program element. The staff's concern described in RAI B.2.1.14-1 is resolved.3-66 3.0.3.2.10 Fire Water System Summary of Technical Information in the Application. LRA Section B.2.1.14 describes the existing Fire Water System Program as being consistent, with enhancements, with GALL AMP XLM27, "Fire Water System." \ The applicant stated that this program manages aging effects for the water-based fire protection system and associated components through the use of periodic inspections, monitoring, and performance testing and provides for preventive measures and inspection activities to detect aging effects prior to loss of intended functions. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the enhancements to determine whether the program, with the enhancements, is adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in GALL AMP XLM27, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. The staff identified an issue with the "acceptance criteria" program element for which the staff requested additional information. The "acceptance criteria" program element of GALL AMP XLM27, states that no biofouling exists in the sprinkler systems that could cause corrosion in the sprinkler heads. In the applicant's Fire Water System Program basis document, the applicant stated that new inspection activities will include an evaluation of identified fouling. During the audit, the applicant indicated that intrusive testing techniques such as ultrasonic testing will be used. In RAI B.2.1.14-1, dated September 29, 2008, the staff requested that the applicant provide additional information to clar1fy how the new ultrasonic examination activity will evaluate fouling. In its response to the RAI dated October 20, 2008, the applicant stated the following: The volumetric non-intrusive examination activities include an evaluation of identified degradation for impact on the system or component function. In accordance with the corrective action process for deficiencies determined to be significantly adverse to quality, the cause of the condition is determined. The aging effect of loss of material can be caused by the aging niechanism of fouling. Fouling would therefore be considered and evaluated as a potential cause of loss of material in fire water service piping. Volumetric examinations do not directly determine fouling as an aging mechanism; however, they provide evidence of the aging effect of loss of material that may result from the aging mechanism of fouling. Based on its review, the staff finds the applicant's response* to RAI B.2.1.14-1 acceptable because the applicant is using a volumetric examination to detect loss of material, and the results would be evaluated by the corrective action process to determine the cause. The staff determines that one of the causes could be fouling in the sprinkler heads, which the applicant considers a potential cause for loss of material. The staff finds that the volumetric examination would detect fouling indirectly as a cause for corrosion and loss of material, and would therefore make the program consistent with the "acceptance criteria" program element. The staff's concern described in RAI B.2.1.14-1 is resolved. 3-66 Enhancement

1. The LRA states an enhancement to the GALL Report as follows:Periodic non-intrusive wall thickness measurements of selected portions of the fire water system at intervals that do not exceed every 10 years.By letter dated October 30, 2008, the applicant stated that this enhancement applies to the"preventive actions," "parameters monitored/inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements.GALL AMP XI.M27 recommends that wall thickness evaluations of fire protection piping be performed at plant-specific intervals using non-intrusive techniques to identify evidence of loss of material due to corrosion.

Based on its review, the staff finds the enhancement acceptable because it will make the FireWater System Program consistent with the GALL Report.Enhancement

2. The LRA states and enhancement to the GALL Report as follows: Sampling of sprinklers in accordance with National Fire Protection Association (NFPA)Standard 25, "Inspection, Testing, and Maintenance of Water-Based Fire Protection Systems," and submitting the samples to a testing laboratory prior to the sprinklers being in service 50 years. Subsequent testing is at intervals that do not exceed every 10 years.GALL AMP XI.M27 recommends testing or replacement of sprinkler heads in service for 50 years.Based on its review, the staff finds the enhancement acceptable because it will make the FireWater System Program consistent with the GALL Report.Operating Experience.

The staff reviewed the operating experience provided in LRA Section B.2.1.14 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.LRA Section B.2.1.14 provides several specific examples of plant operating experience. The applicant stated that following a test run and shut down of the diesel-driven river fire pump in 2005, fire service system pressure lowered until the motor-driven river fire pump auto-started on low fire service header pressure. An investigation indicated an underground piping leak was the cause and subsequently isolated and repaired. The applicant also stated that during performance of fire protection system operations surveillance in 2005, a leak was identified on a threaded elbow. The applicant quantified the leak, evaluated the cause of the leak that turned out to be due to MIC, and determined that it did not impact UFSAR-described or Technical Specification functions, and was not reportable. The applicant subsequently repaired the leak. The applicant also stated that two NRC-conducted triennial fire protection inspections were performed in 2002 and 2005, and only three very low significance findings were identified in the two inspections. During the audit, the staff noted that Issue Report 748645 was issued by the applicant on April 11, 2008, to document corrosion and possible leakage of fire protection piping. In the report, the cause was determined to be heavy tuberculation of MIC causing excessive internal pitting. Issue 3-67 Enhancement

1. The LRA states an enhancement to the GALL Report as follows: Periodic non-intrusive wall thickness measurements of selected portions of the fire water system at intervals that do not exceed every 10 years. By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "preventive actions," "parameters monitored/inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements.

GALL AMP XI.M27 recommends that wall thickness evaluations of fire protection piping be performed at plant-specific intervals using non-intrusive techniques to identify evidence of loss of material due to corrosion. Based on its review, the staff finds the enhancement acceptable because it will make the Fire Water System Program consistent with the GALL Report. Enhancement

2. The LRA states and enhancement to the GALL Report as follows: Sampling of sprinklers in accordance with National Fire Protection Association. (NFPA) Standard 25, "Inspection, Testing, and Maintenance of Water-Based Fire Protection Systems," and submitting the samples to a testing laboratory prior to the sprinklers being in service 50 years. Subsequent testing is at intervals that do not exceed every 10 years. GALL AMP XI. M27 recommends testing or replacement of sprinkler heads in service for 50 years. Based on its review, the staff finds the enhancement acceptable because it will make the Fire Water System Program consistent with the GALL Report. Operating Experience.

The staff reviewed the operating experience provided in LRA Section B.2.1.14 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified* after the issuance of the GALL Report. LRA Section B.2.1.14 provides several specific examples of plant operating experience. The applicant stated that following a test run and shut down of the diesel-driven river fire pump in 2005, fire service system pressure lowered until the motor-driven river fire pump auto-started on low fire service header pressure. An investigation indicated an underground piping leak was the cause and subsequently isolated and repaired. The applicant also stated that during performance of fire protection system operations surveillance in 2005, a leak was identified on a threaded elbow. The applicant quantified the leak, evaluated the cause of the leak that turned out to be due to MIC, and determined that it did not impact UFSAR-described or Technical Specification functions, and was not reportable. The applicant subsequently repaired the leak. The applicant also stated that two NRC-conducted triennial fire protection inspections were performed in 2002 and 2005, and only three very low significance findings were identified in the two inspections. During the audit, the staff noted that Issue Report 748645 was issued by the applicant on April 11, 2008, to document corrosion and possible leakage of fire protection piping. In the report, the cause was determined to be heavy tuberculation of MIC causing excessive internal pitting. Issue 3-67 Report 635626 issued in 2005 indicates that ineffective mitigation of MIC in fire service water system has resulted in degradation of piping, including some through wall leaks.The "preventive actions" program element of the GALL Report AMP XI.M27, states that to ensure no significant corrosion, MIC, or biofouling has occurred in water-based fire protection systems, periodic flushing, system performance testing, and inspections are conducted. The staff noted that the program basis document states that flow tests are conducted once every three years and that these flow tests are intended to provide for an indication of internal piping degradation or fouling. However, based on the above identified issue report, these periodic flow tests may not be adequate. In RAI B.2.1.14-2, September 29, 2008, the staff requested that the applicant provide additional information to identify what preventive measures besides periodic flow testing are proposed to ensure that aging degradation due to MIC is adequately managed during the period of extended operation such that component intended functions are maintained. In its response to the RAI dated October 20, 2008, the applicant stated that in accordance with plant procedures, the fire water system main header is flushed at least once every 12 months; the fire water system deluge and sprinkler systems located in clean areas are flushed once per 18 months; and, in radiation areas the fire water system deluge and sprinkler systems are flushed once per refueling cycle. The applicant also stated that inspection activities include the initiation of periodic non-intrusive fire protection piping wall thickness measurements. The applicant further stated that evaluation of degraded conditions includes determination of where MIC would be considered as a mechanism for loss of material. The applicant also stated that chemical treatment of circulating water has been conducted for approximately 5 years and chemical treatment of river water has been conducted for approximately 1 year. The applicant's implementation of the new water chemistry plan has significantly reduced the number of new MIC leaks per year in circulating water piping. The applicant indicated that the fire service piping identified in this issue report was replaced in November of 2008.Based on its review, the staff finds the applicant's response to RAI B.2.1.14-2 acceptable because the applicant is performing the necessary flushes at periodic intervals to ensure the system is clean of biofouling, has initiated new wall thickness examinations, and has implemented chemical treatment of circulating water and river water, which has reduced number of new MIC leaks per year. The applicant is also replacing the circulating water system piping where these leaks were observed. The staff reviewed the operating experience report and noted that the incidence of MIC related leaks has decreased over the last two years under the new water chemistry plan. The staff also finds that the Fire Water System Program will manage the aging effect of loss of material during the period of extended operation because the applicant has implemented additional measures to ensure that aging degradation due to MIC is managed and that piping with the old MIC leaks have been replaced. The staff's concern described in RAI B.2.1.14-2 is resolved.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. LRA Section A.2.1.14 provides the applicant's UFSAR Supplement for the Fire Water System Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staffs recommended UFSAR Supplement guidance found in the SRP-LR.3-68 Report 635626 issued in 2005 indicates that ineffective mitigation of MIG in fire service water system has resulted in degradation of piping, including some through wall leaks. The "preventive actions" program element of the GALL Report AMP XI.M27, states that to ensure no significant corrosion, MIG, or biofouling has occurred in water-based fire protection systems, periodic flushing, system performance testing, and inspections are conducted. The staff noted that the program basis document states that flow tests are conducted once every three years and that these flow tests are intended to provide for an indication of internal piping degradation or fouling. However, based on the above identified issue report, these periodic flow tests may not be adequate. In RAI B.2.1.14-2, September 29, 2008, the staff requested that the applicant provide additional information to identify what preventive measures besides periodic flow testing are proposed to ensure that aging degradation due to MIG is adequately managed during the period of extended operation such that component intended functions are maintained. In its response to the RAI dated October 20, 2008, the applicant stated that in accordance with plant procedures, the fire water system main header is flushed at least once every 12 months; the fire water system deluge and sprinkler systems located in clean areas are flushed once per 18 months; and, in radiation areas the fire water system deluge and sprinkler systems are flushed once per refueling cycle. The applicant also stated that inspection activities include the initiation of periodic non-intrusive fire protection piping wall thickness measurements. The applicant further stated that evaluation of degraded conditions includes determination of where MIG would be considered as a mechanism for loss of material. The applicant also stated that chemical treatment of circulating water has been conducted for approximately 5 years and chemical treatment of river water has been conducted for approximately 1 year. The applicant's implementation of the new water chemistry plan has significantly reduced the number of new MIG leaks per year in circulating water piping. The applicant indicated that the fire service piping identified in this issue report was replaced in November of 2008. Based on its review, the staff finds the applicant's response to RAI B.2.1.14-2 acceptable because the applicant is performing the necessary flushes at periodic intervals to ensure the system is clean of biofouling, has initiated new wall thickness examinations, and has implemented chemical treatment of circulating water and river water, which has reduced number of new MIG leaks per year. The applicant is also replacing the circulating water system piping where these leaks were observed. The staff reviewed the operating experience report and noted that the . incidence of MIG related leaks has decreased over the last two years under the new water chemistry plan. The staff also finds that the FireWater System Program will manage the aging effect of loss of material during the period of extended operation because the applicant has implemented additional measures to ensure that aging degradation due to MIG is managed and that piping with the old MIG leaks have been replaced. The staff's concern described in RAI B.2.1.14-2 is resolved. ' The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1

o. The staff finds this program element acceptable.

UFSAR Supplement. LRA Section A.2.1.14 provides the applicant's UFSAR Supplement for the Fire Water System Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR. 3-68 In LRA Section A.5, Commitment No. 14, the applicant committed to enhance its program to require testing or replacement of sprinkler heads in service for 50 years, and to perform periodic non-intrusive wall thickness measurements of selected portions of the fire water system at intervals not exceeding 10 years prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Fire Water System Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Fire Water System Program, and the applicant's response to the RAIs, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. The staff reviewed the enhancements and confirmed that their implementation through Commitment No. 14 prior to the period of extended operation will make the existing AMP consistent with the GALL AMP to which it was compared. 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). The staff also reviewed the UFSAR Supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.11 Aboveground Steel Tanks Summary of Technical Information in the Application. LRA Section B.2.1.15 describes the existing Aboveground Steel Tanks Program as being consistent, with an exception and enhancements, to GALL AMP XI.M29, "Aboveground Steel Tanks." The applicant stated that this program is credited to manage loss of material aging effects for those tanks that are fabricated of carbon steel and located outdoors. The applicant further stated that as part of this program, periodic visual inspections will be performed to monitor for any degradation of paint, sealant at the tank-foundation interface, and potential loss of material of the underlying metal. The applicant will enhance its existing implementing procedures to perform a one-time UT inspection on the bottom of the applicable tanks that are located on a concrete foundation in order to confirm that degradation has not occurred.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception and enhancements to determine whether the AMP, with the exception and enhancements is adequate to manage the aging effects for which the LRA credits it.In comparing the elements in the applicant's program to those in GALL AMP XI.M29, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. The staff identified issues with the "scope of program," program element, and portions of other program elements related to the exception and enhancements for which the staff requested additional information. The staff noted that in the applicant's program basis document under the program description and"scope of program" program element, the outdoor carbon steel tanks that are within the scope of this program include only the Condensate Storage Tank, Fire Service Water Head Tank (Altitude Tank), and the Sodium Hydroxide Tank. Each of these tanks is fabricated from carbon steel.Upon review of the applicant's aging management review line items, the staff noted that this AMP was credited for aging management of the Sodium Thiosulfate Tank which is fabricated from stainless steel. In RAI B.2.1.15-1, dated September 29, 2008, the staff requested that the 3-69 In LRA Section A.5, Commitment No. 14, the applicant committed to enhance its program to require testing or replacement of sprinkler heads in service for 50 years, and to perform periodic non-intrusive wall thickness measurements of selected portions of the fire water system at intervals not exceeding 10 years prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Fire Water System Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Fire Water System Program, and the applicant's response to the RAls, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. The staff reviewed the enhancements and confirmed that their implementation through Commitment No. 14 prior to the period of extended operation will make the existing AMP consistent with the GALL AMP to which it was compared. 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). The staff also reviewed the UFSAR Supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.11 Aboveground Steel Tanks Summary of Technical Information in the Application. LRA Section 8.2.1.15 describes the existing Aboveground Steel Tanks Program as being consistent, with an exception and enhancements, to GALL AMP XI.M29, "Aboveground Steel Tanks." The applicant stated that this program is credited to manage loss of material aging effects for those tanks that are fabricated of carbon steel and located outdoors. The applicant further stated that as part of this program, periodic visual inspections will be performed to monitor for any degradation of paint, sealant at the tank-foundation interface, and potential loss of material of the underlying metal. The applicant will enhance its existing implementing procedures to perform a one-time UT inspection on the bottom of the applicable tanks that are located on a concrete foundation in order to confirm that degradation has not occurred. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception and enhancements to determine whether the AMP, with the exception and enhancements is adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in GALL AMP XI.M29, the staff determined that those program elements for which the applicant claimed conSistency with the GALL Report, are consistent. The staff identified issues with the "scope of program," program element, and portions of other program elements related to the exception and enhancements for which the staff requested additional information. The staff noted that in the applicant's program basis document under the program description and "scope of program" program element, the outdoor carbon steel tanks that are within the scope of this program include only the Condensate Storage Tank, Fire Service Water Head Tank (Altitude Tank), and the Sodium Hydroxide Tank. Each of these tanks is fabricated from carbon steel. Upon review of the applicant's aging management review line items, the staff noted that this AMP was credited for aging management of the Sodium Thiosulfate Tank which is fabricated from stainless steel. In RAI 8.2.1.15-1, dated September 29, 2008, the staff requested that the 3-69 applicant provide additional information to clarify whether this AMP is credited for aging management for aboveground steel tanks fabricated of carbon steel and stainless steel and whether the Sodium Thiosulfate Tank requires a one-time UT inspection of the bottom of the tank.In its response to the RAI dated October 20, 2008, the applicant stated that this program is only intended for aboveground tanks fabricated from steel, and that aboveground stainless steel tanks, including the Sodium Thiosulfate Tank, are not within the scope of this program. The applicant further stated that an error was made in LRA Table 3.2.2-5, when the Aboveground Steel Tanks Program was credited for aging management of the Sodium Thiosulfate Tank. The staff confirmed that the applicant had sufficiently described the details of the amendment to this AMR line item.Based on its review, the staff finds the applicant's response to RAI B.2.1.15-1 acceptable because the applicant has identified that the AMP should not have been credited for aging management of the aboveground stainless steel tanks. Additionally, the applicant amended the LRA to credit the appropriate AMP to manage the aging effect of loss of material for the Sodium Thiosulfate Tank. The staff's concern described in RAI B.2.1.15-1 is resolved.Exception

1. The LRA states an exception to the GALL Report as follows: NUREG-1 801 states that periodic plant system walkdowns each outage are used to monitor degradation.

The TMI-1 program utilizes tank inspections at least every five years in place of periodic system walkdowns each outage. Tank components subject to outdoor air are constructed from carbon steel. The carbon steel tanks are protected by a protective coating. Industry guidance and experience indicate that monitoring of exterior surfaces of components made of this material and protective coating on a frequency of at least every five years provides reasonable assurance that loss of material will be detected before an intended function is affected.By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects," and "monitoring and trending" program elements.GALL AMP XI.M29 states that based on operating experience system, walkdowns during each outage will provide for timely detection of aging effects. The LRA states that this exception toGALL is being taken based on industry guidance and industry operating experience. The staff determined that additional information was needed pertaining to the industry guidance and industry experience relied upon by the applicant for this exception. In RAI B.2.1.15-3, dated September 29, 2008, the staff requested the applicant provide additional information to clarify the current inspection frequency of all tanks within the scope of this program. The staff also asked the applicant to provide the detailed industry guidance and industry experience that is referred to in the exception and to justify the basis for not performing walkdowns each refueling outage as recommended by GALL AMP XI.M29.In its response to the RAI dated October 20, 2008, the applicant stated that inspection frequency for all carbon steel tanks that are within the scope of License Renewal will be five years. The applicant further stated that this five-year frequency is consistent with its Structures Monitoring Program, for external surfaces of the tanks' supporting structures and with industry guidelines as stated on page 5-30 of SAND96-0343, "Aging Management Guideline for Commercial NuclearPower Plants -Tanks and Pools," that have been proven to be effective in detecting loss of material prior to loss of intended functions. In its supplemental response to the RAI dated December 5, 2008 the applicant stated that the five-year frequency is consistent with 3-70 applicant provide additional information to clarify whether this AMP is credited for aging management for aboveground steel tanks fabricated of carbon steel and stainless steel and whether the Sodium Thiosulfate Tank requires a one-time UT inspection of the bottom of the tank: In its response to the RAI dated October 20, 2008, the applicant stated that this program is only intended for aboveground tanks fabricated from steel, and that aboveground stainless steel tanks, including the Sodium Thiosulfate Tank, are not within the scope of this program. The applicant further stated that an error was made in LRA Table 3.2.2-5, when the Aboveground Steel Tanks Program was credited for aging management of the Sodium Thiosulfate Tank. The staff confirmed that the applicant had sufficiently described the details of the amendment to this AMR line item. Based on its review, the staff finds the applicant's response to RAI B.2.1.15-1 acceptable because the applicant has identified that the AMP should not have been credited for aging management of the aboveground stainless steel tanks. Additionally, the applicant amended the LRA to credit the appropriate AMP to manage the aging effect of loss of material for the Sodium Thiosulfate Tank. The staff's concern described in RAI B.2.1.15-1 is resolved. Exception

1. The LRA states an exception to the GALL Report as follows: NUREG-1801 states that periodic plant system walkdowns each outage are used to monitor degradation.

The TMI-1 program utilizes tank inspections at least every five years in place of periodic system walkdowns each outage. Tank components subject to outdoor air are constructed from carbon steel. The carbon steel tanks are protected by a protective coating. Industry guidance and experience indicate that monitoring of exterior surfaces of components made of this material and protective coating on a frequency of at least every five years provides reasonable assurance that loss of material will be detected before an intended function is affected. By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program," "parameters monitoredlinspected," "detection of aging effects," and "monitoring and trending" program elements. GALL AMP XI.M29 states that based on operating experience system, walkdowns during each outage will provide for timely detection of aging effects. The LRA states that this exception to GALL is being taken based on industry guidance and industry operating experience. The staff determined that additional information was needed pertaining to the industry guidance and industry experience relied upon by the applicant for this exception. In RAI B.2.1.15-3, dated September 29, 2008, the staff requested the applicant provide additional information to clarify the current inspection frequency of all tanks within the scope of this program. The staff also asked the applicant to provide the detailed industry guidance and industry experience that is referred to in the exception and to justify the basis for not performing walkdowns each refueling outage as recommended by GALL AMP XI.M29. In its response to the RAI dated October 20, 2008, the applicant stated that inspection frequency for all carbon steel tanks that are within the scope of License Renewal will be five years. The applicant further stated that this five-year frequency is consistent with its Structures Monitoring Program, for external surfaces of the tanks' supporting structures and with industry guidelines as stated on page 5-30 of SAND96-0343, "Aging Management Guideline for Commercial Nuclear Power Plants -Tanks and Pools," that have been proven to be effective in detecting loss of material prior to loss of intended functions. In its supplemental response to the RAI dated December 5, 2008 the applicant stated that the five-year frequency is consistent with 3-70 Maintenance Rule (10 CFR 50.65) requirements. The staff noted that the applicant's Structures Monitoring Program was developed based on guidance in RG 1.160, Revision 2, and NUMARC 93-01, Revision 2, to satisfy the requirement of 10 CFR 50.65.Based on its review, the staff finds the applicant's response to RAI B.2.1.15-3 acceptable and also finds the exception to the GALL Report acceptable because the five-year frequency is consistent with the inspections performed as part of the Structures Monitoring Program which meets the requirements of 10 CFR 50.65. The staffs concern described in RAI B.2.1.15-3 is resolved.Enhancement

1. The LRA states an enhancement to the GALL Report as follows: The existing TMI-1 Aboveground Steel Tanks program implementing procedures will be enhanced to include one-time thickness measurements of the bottom of the Condensate Storage Tanks, which are supported on concrete foundations.

Measurements will be taken to ensure that significant degradation is not occurring and the component intended function will be maintained during the extended period of operation. By letter dated October 30, 2008, the applicant stated that this enhancement applies to the"detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements.The staff noted that of the aboveground steel tanks in the scope of this program only the Condensate Storage Tanks require a one-time UT inspection of the bottom of the tank to determine its condition. Additionally, the staff noted that the remaining tanks within the scope of the program, (the Fire Service Water Tank (Altitude Tank) and the Sodium Hydroxide Tank), are not directly supported by a concrete foundation and therefore, the one-time UT inspection is not required because a visual inspection of the tank bottom can be performed during tank inspections. Based on its review, the staff finds the enhancement acceptable because performing this thickness, measurement is consistent with GALL AMP XI.M29.Enhancement

2. The LRA states an enhancement to the GALL Report as follows: The program will also be enhanced to inspect the condition of the sealant between CSTs and the concrete foundations.

By letter dated October 30, 2008, the applicant stated that this enhancement applies to the"parameters monitored/inspected," "detection of aging effects," and "monitoring and trending" program elements.The staff determined that additional information was needed regarding the inspection of the sealant (concrete grout) at the tank to foundation interface. The staff noted that this program is being credited for aging management of the sealants/caulking and paint/coatings that are used on the aboveground steel tanks. However, based on the staff's review of the AMR line items in LRA Section 3, the staff noted that this AMP has not been credited for aging management of these materials. In RAI B.2.1.15-2, dated September 29, 2008, the staff requested the applicant provideadditional information to clarify whether paints/coatings used on the external surface of the tanks and sealants/caulking used at the tank-foundation interface will be inspected as part of the AMP.The applicant was also requested to provide additional information to indicate the program that is 3-71 Maintenance Rule (10 CFR 50.65) requirements. The staff noted that the applicant's Structures Monitoring Program was developed based on guidance in RG 1.160, Revision 2, and NUMARC 93-01, Revision 2, to satisfy the requirement of 10 CFR 50.65. Based on its review, the staff finds the applicant's response to RAI B.2.1.15-3 acceptable and also finds the exception to the GALL Report acceptable because the five-year frequency is consistent with the inspections performed as part of the Structures Monitoring Program which meets the requirements of 10 CFR 50.65. The staff's concern described in RAI B.2.1.15-3 is resolved. Enhancement

1. The LRA states an enhancement to the GALL Report as follows: The existing TMI-1 Aboveground Steel Tanks program implementing procedures will be enhanced to include one-time thickness measurements of the bottom of the Condensate Storage Tanks, which are supported on concrete foundations.

Measurements will be taken to ensure that significant degradation is not occurring and the component intended function will be maintained during the extended period of operation. By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements. The staff noted that of the aboveground steel tanks in the scope of this program only the Condensate Storage Tanks require a one-time UT inspection of the bottom of the tank to determine its condition. Additionally, the staff noted that the remaining tanks within the scope of the program, (the Fire Service Water Tank (Altitude Tank) and the Sodium Hydroxide Tank), are not directly supported by a concrete foundation and therefore, the one-time UT inspection is not required because a visual inspection of the tank bottom can be performed during tank inspections. Based on its review, the staff finds the enhancement acceptable because performing this thickness measurement is consistent with GALL AMP XI.M29. Enhancement

2. The LRA states an enhancement to the GALL Report as follows: The program will also be enhanced to inspect the condition of the sealant between CSTs and the concrete foundations.

By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "parameters monitored/inspected," "detection of aging effects," and "monitoring and trending" program elements. The staff determined that l;ldditional information was needed regarding the inspection of the sealant (concrete grout) at the tank to foundation interface. The staff noted that this program is being credited for aging management of the sealants/caulking and paint/coatings that are used on the aboveground steel tanks. However, based on the staff's review of the AMR line items in LRA Section 3, the staff noted that this AMP has not been credited for aging management of these materials. In RAI B.2.1.15-2, dated September 29, 2008, the staff requested the applicant provide additional information to clarify whether paints/coatings used on the external surface of the tanks and sealants/caulking used at the tank-foundation interface will be inspected as part of the AMP. The applicant was also requested to provide additional information to indicate the program that is 3-71 credited for aging management of paint/coatings on the external surface and sealants and caulkings at the tank-foundation interface if this AMP is not credited.In it response to the RAI dated October 20, 2008, the applicant stated the Condensate Storage Tanks are the only tanks managed by this AMP that are supported by a concrete foundation and have sealant (concrete grout) at the tank to foundation interface. The applicant also stated that the application and presence of the caulking/sealants and paints/coatings are design features and serve as only preventative measures for onset of corrosion. The staff noted that the applicant hasnot credited paints/coatings and caulking/sealants as they do not perform any intended function and are not within the scope of license renewal. However, the staff noted that as part of the visualinspection performed as part of this AMP, the applicant will inspect the condition of the paint/coatings and the condition of the sealant at the tank to foundation interface which will provide an indication of the condition of the underlying carbon steel material.Based on its review, the staff finds the applicant's response to RAI B.2.1.15-2 acceptable because (1) the applicant has not credited paints/coatings and caulking/sealants with preventing and mitigating aging of the Condensate Storage Tanks, and therefore they do not require aging management and (2) the applicant will perform periodic visual inspections of the paints/coatings and caulking/sealants of these tanks which will provide an indication of the condition of theunderlying metallic material, even though these design features do not perform an intended function and are not in the scope of License Renewal. The staff's concern described in RAI B.2.1.15-2 is resolved.Based on its review, the staff finds the enhancement acceptable because it is consistent with the recommendations provided in GALL AMP XI.M29. Operatinq Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.15 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The staff noted that on June 13, 2005, the applicant discovered blistering and missing paint on the Altitude Tank, although there was no indication of rust or leaks. The applicant initiated a recurring task to inspect this tank on an annual basis to ensure that further degradation would not occur without it being discovered. The staff reviewed the inspection results from June 2007, and noted that the applicant found the tank did not have significant corrosion and had not further degraded from the previous year's inspection. The staff noted that during an inspection of the Altitude Tank in June 2007 that pieces of insulation were discovered missing from piping locations on the upper and lower platform level.During this inspection the applicant noted mild to no rust conditions in the areas where the insulation was missing. The staff noted the results from the latest inspection in June 2008, which indicated the corrosion on the tank where the insulation is missing is not significant. The staff noted that the work to address the missing insulation is planned to occur during the next refueling outage scheduled for Fall of 2009. The staff also noted that the Altitude Tank will be capable of performing its intended functions until the scheduled work to replace the missing insulation is conducted during the Fall 2009 refueling outage because of the minimal degradation that waspresent based on recent inspections of these locations. The staff further noted that the applicant 3-72 credited for aging management of paint/coatings on the external surface and sealants and caulkings at the tank-foundation interface if this AMP is not credited. In it response to the RAI dated October 20, 2008, the applicant stated the Condensate Storage Tanks are the only tanks managed by this AMP that are supported by a concrete foundation and have sealant (concrete grout) at the tank to foundation interface. The applicant also stated that the application and presence of the caulking/sealants and paints/coatings are design features and serve as only preventative measures for onset of corrosion. The staff noted that the applicant has not credited paints/coatings and caulking/sealants as they do not perform any intended function and are not within the scope of license renewal. However, the staff noted that as part of the visual inspection performed as part of this AMP, the applicant will inspect the condition of the paint/coatings and the condition of the sealant at the tank to foundation interface which will provide an indication of the condition of the underlying carbon steel material. Based on its review, the staff finds the applicant's response to RAI B.2.1.15-2 acceptable because (1) the applicant has not credited paints/coatings and caulking/sealants with preventing and mitigating aging of the Condensate Storage Tanks, and therefore they do not require aging management and (2) the applicant will perform periodic visual inspections of the paints/coatings and caulking/sealants of these tanks which will provide an indication of the condition of the underlying metallic material, even though these design features do not perform an intended function and are not in the scope of License Renewal. The staff's concern described in RAI B.2.1.15-2 is resolved. Based on its review, the staff finds the enhancement acceptable because it is consistent with the recommendations provided in GALL AMP XI.M29. Operating Experience. The staff reviewed the operating experience provided in LRA Section B2.1.15 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The staff noted that on June 13, 2005, the applicant discovered blistering and missing paint on the Altitude Tank, although there was no indication of rust or leaks. The applicant initiated a recurring task to inspect this tank on an annual basis to ensure that further degradation would not occur without it being discovered. The staff reviewed the inspection results from June 2007, and noted that the applicant found the tank did not have significant corrosion and had not further degraded from the previous year's inspection. The staff noted that during an inspection of the Altitude Tank in June 2007 that pieces of insulation were discovered missing from piping locations on the upper and lower platform level. During this inspection the applicant noted mild to no rust conditions in the areas where the insulation was missing. The staff noted the results from the latest inspection in June 2008, which indicated the corrosion on the tank where the insulation is missing is not significant. The staff noted that the work to address the missing insulation is planned to occur during the next refueling outage scheduled for Fall of 2009. The staff also noted that the Altitude Tank will be capable of performing its intended functions until the scheduled work to replace the missing insulation is conducted during the Fall 2009 refueling outage because of the minimal degradation that was present based on recent inspections of these locations. The staff further noted that the applicant 3-72* has been capable of identifying corrosion, has taken corrective actions to inspect this tank yearly to trend any degradation and has work scheduled to address the missing insulation. Based on its review, the staff finds (1) that the operating experience for this AMP demonstrates that the AMP is achieving its objective of managing system components; and (2) that the applicant is taking appropriate corrective actions through implementation of this AMP.The staff confirmed 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. LRA Section A.2.1.15 provides the applicant's UFSAR Supplement for theAboveground Steel Tanks Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staffs recommended UFSAR Supplement guidance found in the SRP-LR.In LRA Section A.5, Commitment No. 15, the applicant committed to enhancing the existing program by revising the implementing procedure to include a one-time UT measurement of the CSTs bottoms and by inspecting the sealant at the tank-foundation interface prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Aboveground Steel Tanks Program as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's Aboveground Steel Tanks Program, and the applicant's responses to the RAI's, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exception and the associated justification and determined that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. The staff also reviewed the enhancements and confirmed that with their implementation, through Commitment No. 15 prior to the period of extended operation, the existing program will be consistent with the GALL AMP with which it was compared. The staff concludes that the applicant has demonstrated that effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.12 Fuel Oil Chemistry Summary of Technical Information in the Application. LRA Section B.2.1.16 describes the applicant's existing Fuel Oil Chemistry Program as being consistent, with exceptions and enhancements, to GALL AMP XI.M30, "Fuel Oil Chemistry."The applicant stated that the program provides preventive actions that maintain contaminants, such as water, particulate and sediment, in fuel oil systems at acceptable levels. The applicant also stated that contaminants are controlled and monitored in accordance with site technical specifications and applicable American Society for Testing and Materials (ASTM) standards and that the program manages loss of material due to general, pitting, crevice corrosion microbiologically-influenced corrosion, and biological fouling.3-73 has been capable of identifying corrosion, has taken corrective actions to inspect this tank yearly to trend any degradation and has work scheduled to address the missing insulation. Based on its review, the staff finds (1) that the operating experience for this AMP demonstrates that the AMP is achieving its objective of managing system components; and (2) that the applicant is taking appropriate corrective actions through implementation of this AMP. The staff confirmed the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1 O. The staff finds this program element acceptable. UFSAR Supplement. LRA Section A.2.1.15 provides the applicant's UFSAR Supplement for the Aboveground Steel Tanks Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staffs recommended UFSAR Supplement guidance found in the SRP-LR. In LRA Section A.5, Commitment No. 15, the applicant committed to enhancing the existing program by revising the implementing procedure to include a one-time UT measurement of the CSTs bottoms and by inspecting the sealant at the tank-foundation interface prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the* Aboveground Steel Tanks Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its review and audit of the applicant's Aboveground Steel Tanks Program, and the applicant's responses to the RAl's, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exception and the associated justification and determined that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. The staff also reviewed the enhancements and confirmed that with their implementation, through Commitment No. 15 prior to the period of extended operation, the existing program will be consistent with the GALL AMP with which it was compared. The staff concludes that the applicant has demonstrated that effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.12 Fuel Oil Chemistry Summary of Technical Information in the Application. LRA Section B.2.1.16 describes the applicant's existing Fuel Oil Chemistry Program as being consistent, with exceptions and enhancements, to GALL AMP XJ.M30, "Fuel Oil Chemistry." The applicant stated that the program provides preventive actions that maintain contaminants, such as water, particulate and sediment, in fuel oil systems at acceptable levels. The applicant also stated that contaminants are controlled and monitored in accordance with site technical specifications and applicable American Society for Testing and Materials (ASTM) standards and that the program manages loss of material due to general, pitting, crevice corrosion microbiologically-influenced corrosion, and biological fouling. 3-73 Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exceptions and enhancements to determine whether the AMP, with the exceptions and enhancements, is adequate to manage the aging effects for which the LRA credits it.In comparing the elements in the applicant's program to those in GALL AMP XI.M30, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. Exception

1. The LRA states an exception to the GALL Report as follows: NUREG-1 801 states in XI.M30 that the fuel oil aging management program is focused onmanaging the conditions that cause general, pitting, and microbiologically-influenced corrosion (MIC). The TMI-1 aging mechanisms in fuel oil also include the loss of material due to crevice corrosion and biological fouling. The contaminants that cause crevice corrosion and biological fouling are similar to those that cause general, pitting and microbiologically-influenced corrosion (MIC). Therefore, the monitoring and inspection techniques used to manage the conditions that cause general, pitting, and microbiologically-influenced corrosion (MIC) will be effective in managing the loss of material due to crevice corrosion and biological fouling.By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program," "preventive actions," "parameters monitored/inspected," "detection of aging effects," and, "monitoring and trending" program elements.The "scope of program" element of GALL AMP XI.M30, states that the program is focused on managing the conditions that cause general, pitting, and MIC of the diesel fuel tank internal surfaces.

Fouling and crevice corrosion are not specifically included as an aging mechanisms managed by GALL AMP XI.M30. The staff noted that water, sediment, and particulate contamination of fuel oil could cause loss of material due to general corrosion, pitting, and MIC.The staff notes that these contaminants can also lead to fouling and crevice corrosion. In addition, monitoring and maintaining contamination (water and particulate) below acceptable levels in fuel oil systems and periodic cleaning of tanks will be effective methods to manage biological fouling because these contaminants are necessary for biological fouling to occur. The staff also noted that water, particulate, and sediment can cause crevice corrosion, which can occur in localized areas where contaminants can be trapped, leading to degradation similar to pitting corrosion and controlling contaminant levels, periodic cleaning and visual inspection of fuel oil tanks are effective means to minimize and detect crevice corrosion. Therefore, the staff finds that the contaminants that cause general, pitting, and MIC can also cause crevice corrosion and biological fouling and the methods used to manage general corrosion, pitting corrosion, and MIC are also effective for crevice corrosion and biological fouling.Based on its review, the staff finds this exception to the GALL report acceptable because the contaminants that cause general, pitting, and MIC can also cause crevice corrosion and biological fouling and the methods used to manage general corrosion, pitting corrosion, and MIC are also effective for crevice corrosion and biological fouling.3-74 Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exceptions and enhancements to determine whether the AMP, with the exceptions and enhancements, is adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in GALL AMP XI.M30, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. Exception

1. The LRA states an exception to the GALL Report as follows: NUREG-1801 states in XI.M30 that the fuel oil aging management program is focused on managing the conditions that cause general, pitting, and microbiologically-influenced corrosion (MIG). The TMI-1 aging mechanisms in fuel oil also include the loss of material due to crevice corrosion and biological fouling. The contaminants that cause crevice corrosion and biological fouling are similar to those that cause general, pitting and microbiologically-influenced corrosion (MIC). Therefore, the monitoring and inspection techniques used to manage the conditions that cause general, pitting, and microbiologically-influenced corrosion (MIC) will be effective in managing the loss of material due to crevice corrosion and biological fouling. By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program," "preventive actions," "parameters monitoredlinspected," "detection of aging effects," and, "monitoring and trending" program elements.

The "scope of program" element of GALL AMP XI.M30, states that the program is focused on managing the conditions that cause general, pitting, and MIC of the diesel fuel tank internal. surfaces. Fouling and crevice corrosion are not specifically included as an aging mechanisms managed by GALL AMP XI.M30. The staff noted that water, sediment, and particulate contamination of fuel oil could cause loss of material due to general corrosion, pitting, and MIG. The staff notes that these contaminants can also lead to fouling and crevice corrosion. In addition, monitoring and maintaining contamination (water and particulate) below acceptable levels in fuel oil systems and periodic cleaning of tanks will be effective methods to manage biological fouling because these contaminants are necessary for biological fouling to occur. The staff also noted that water, particulate, and sediment can cause crevice corrosion, which can occur in localized areas where contaminants can be trapped, leading to degradation similar to pitting corrosion and controlling contaminant levels, periodic cleaning and visual inspection of fuel oil tanks are effective means to minimize and detect crevice corrosion. Therefore, the staff finds that the contaminants that cause general, pitting, and MIG can also cause crevice corrosion and biological fouling and the methods used to manage general corrosion, pitting corrosion, and MIG are also effective for crevice corrosion and biological fouling. Based on its review, the staff finds this exception to the GALL report acceptable because the contaminants that cause general, pitting, and MIG can also cause crevice corrosion and biological fouling and the methods used to manage general corrosion, pitting corrosion, and MIG are also effective for crevice corrosion and biological fouling. 3-74 Exception

2. The LRA states an exception to the GALL Report as follows: NUREG-1801 states in XI.M30 that the fuel oil aging management program is in part based on the fuel oil purity and testing requirements of the plant's Technical Specifications that are based on the Standard Technical Specifications of NUREG-1 430 through NUREG-1433. TMI-1 has not adopted the Standard Technical Specifications as described in these NUREGs; however, the TMI-1 fuel oil specifications and procedures invoke equivalent requirements for fuel oil purity and fuel oil testing as described by the Standard Technical Specifications.

By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program," and "monitoring and trending," program elements.The staff noted that the applicant's definition of "equivalent requirements" as stated in this exception is not clear. In RAI B.2.1.16-1, dated September 29, 2008, the staff requested that the applicant provide additional information that included a direct comparison between the Standard TS and the plant fuel oil specifications along with a justification for any difference in fuel oil purity and testing parameters. In its response to the RAI dated October 20, 2008, the applicant provided a comparison of the Standard Technical Specifications, Section 5.5.13 of NUREG-1 430, with the plant fuel oil specifications. The staff noted that the plant fuel oil specifications meet requirements of NUREG-1430 for new fuel oil and stored fuel except for the frequency for determining total particulate concentration. As indicated by the applicant, the test frequency for total particulate concentration of 91 days is in accordance with GALL AMP XI.M30.Based on its review, the staff finds the applicant's response to RAI B.2.1.16-1 acceptable because the plant fuel oil specifications meet the requirements of NUREG-1 430 for new and stored fuel oil except for the frequency for determining total particulate concentration, which in this case is 91 days which is in accordance with GALL AMP XI.M30. The staffs concern described in RAI B.2.1.16-1 is resolved.Based on its review, the staff finds that the exception is acceptable because the AMP meets the GALL Report recommendations for fuel oil quality parameters. Exception

3. The LRA states an exception to the GALL Report as follows: NUREG-1801 states that the program serves to reduce the potential of exposure of the tank internal surface to fuel oil contaminated with water and biological organisms.

This is accomplished by analyzing multilevel samples for water and sediment, biological activity,and particulate on a periodic basis (at least quarterly). Fuel oil tanks should also be periodically drained of accumulated water and sediment, and, periodically drained, cleaned, and internally inspected. The following are exceptions to these requirements: Multilevel sampling, tank bottom draining, cleaning, and internal inspection of the 7.3 gallon Station Blackout Diesel Clean Fuel Tank is not periodically performed at TMI-1. This tank is integral to the routine operation of the Station Blackout Diesel and collects excess clean fuel oil from the diesel engine that has been previously analyzed within its managed source tank, the Station Blackout Diesel Fuel Storage Tank. The Clean Fuel Tank is small in size and experiences a turnover of the fuel collected within as a result of routine engine operation. Therefore, the periodic draining of water and sediment from the bottom of the Clean Fuel Tank, and, the periodic 3-75 Exception

2. The LRA states an exception to the GALL Report as follows: NUREG-1801 states in XLM30 that the fuel oil aging management program is in part based on the fuel oil purity and testing requirements of the plant's Technical Specifications that are based on the Standard Technical Specifications of NUREG-1430 through NUREG-1433. TMI-1 has not adopted the Standard Technical Specifications as described in these NUREGs; however, the TMI-1 fuel oil specifications and procedures invoke equivalent requirements for fuel oil purity and fuel oil testing as described by the Standard Technical Specifications.

By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program," and "monitoring and trending," program elements. The staff noted that the applicant's definition of "equivalent requirements" as stated in this exception is not clear. In RAI B.2.1.16-1, dated September 29, 2008, the staff requested that the applicant provide additional information that included a direct comparison between the Standard TS and the plant fuel oil specifications along with a justification for any difference in fuel oil purity and testing parameters. In its response to the RAI dated October 20, 2008, the applicant provided a comparison of the Standard Technical Specifications, Section 5.5.13 of NUREG-1430, with the plant fuel oil specifications. The staff noted that the plant fuel oil specifications meet requirements of NUREG-1430 for new fuel oil and stored fuel except for the frequency for determining total particulate concentration. As indicated by the applicant, the test frequency for total particulate concentration of 91 days is in accordance with GALL AMP XLM30. Based on its review, the staff finds the applicant's response to RAI 8.2.1.16-1 acceptable because the plant fuel oil specifications meet the requirements of NUREG-1430 for new and stored fuel oil except for the frequency for determining total particulate concentration, which in this case is 91 days which is in accordance with GALL AMP XLM30. The staffs concern described in RAI B.2.1.16-1 is resolved. Based on its review, the staff finds that the exception is acceptable because the AMP meets the GALL Report recommendations for fuel oil quality parameters. Exception

3. The LRA states an exception to the GALL Report as follows: NUREG-1801 states that the program serves to reduce the potential of exposure of the tank internal surface to fuel oil contaminated with water and biological organisms.

This is accomplished by analyzing multilevel samples for water and sediment, biological activity, and particulate on a periodic basis (at least quarterly). Fuel oil tanks should also be periodically drained of accumulated water and sediment, and, periodically drained, cleaned, and internally inspected. The foflowingare exceptions to these requirements: Multilevel sampling, tank bottom draining, cleaning, and internal inspection of the 7.3 gallon Station Blackout Diesel Clean Fuel Tank is not periodically performed at TMI-1. This tank is integral to the routine operation of the Station Blackout Diesel and collects excess clean fuel oil from the diesel engine that has been previously analyzed within its managed source tank, the Station Blackout Diesel Fuel Storage Tank. The Clean Fuel Tank is small in size and experiences a turnover of the fuel collected within as a result of routine engine operation. Therefore, the periodic draining of water and sediment from the bottom of the Clean Fuel Tank, and, the periodic 3-75 draining, cleaning, and internal inspections are not necessary. To confirm the absence of any significant aging effects, a one-time inspection of the Station Blackout Diesel Clean Fuel Tank will be performed as part of the TMI-1 Fuel Oil Chemistry AMP. Should the one-time inspection reveal evidence of aging effects, this condition will be entered into the corrective action process for resolution. Multilevel sampling, tank bottom draining, cleaning, and internal inspection of the 550 gallon Station Blackout Diesel Fuel Day Tank is not periodically performed at TMI-1. This tank is integral to the routine operation of the Station Blackout Diesel and is filled with fuel oil that has been previously analyzed within its managed source tank, the Station Blackout Diesel Fuel Storage Tank. The fuel oil within the Day Tank is recirculated to the Station Blackout Diesel Fuel Storage Tank quarterly to prevent the accumulation of contaminants and water and sediment. Therefore, the periodic draining of water and sediment from the bottom of the Day Tank, and, the periodic draining, cleaning, and internal inspections are not necessary. To confirm the absence of any significant aging effects, a one-time inspection of the Station Blackout Diesel Day Tank will be performed as part of the TMI-1 Fuel Oil Chemistry AMP. Should the one-time inspection reveal evidence of aging effects, this condition will be entered into the corrective action process for resolution. By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program" program element.The staff noted that it is not clear why these tanks can't be periodically drained, cleaned, and periodically inspected and the extent of UT examination of the tank bottoms. In RAI B.2.1.16-2, dated September 29, 2008, the staff requested that the applicant provide additional information concerning the design features and the extent of the UT inspection planned for the tank bottoms.In its response to the RAI dated October 20, 2008, the applicant provided design details for the 550 gallon diesel fuel oil day tank and the 7.3 gallon diesel clean fuel oil tank. The applicant stated that design features, such as manholes or hatches do not exist in these tanks, and do not allow them to be readily inspected and cleaned or to allow multilevel sampling from these tanks.The applicant stated it will rely on a one-time volumetric examination of the exterior of the bottoms of these tanks to verify loss of material has not occurred in these tanks. The applicant stated that an internal visual inspection may be substituted in place of the volumetric inspection and if loss of material is detected by either external volumetric inspection or interior visual inspection, the finding will be entered into the corrective action process which will identify additional actions necessary to manage the degradation through the period of extended operation. Based on its review, the staff finds the applicant's response to RAI B.2.1.16-2 acceptable and also the exception to the GALL Report acceptable because 1) volumetric inspections of the exterior of the tank bottoms, or as an option, interior visual inspection of these tanks, will detect tank wall degradation prior to loss of the intended function of these tanks; and 2) actions will be identified and executed through the corrective action process to assure the intended function of the tanks will be maintained through the period of extended operation if degradation is found.Exception

4. The LRA states an exception to the GALL Report as follows: NUREG-1801 requires periodic multilevel sampling of tanks in accordance with themanual sampling standards of ASTM D 4057-95 (2000). TMI-1 has not committed to ASTM D 4057-95 (2000) for manual sampling standards:

3-76 draining, cleaning, and internal inspections are not necessary. To confirm the absence of any significant aging effects, a one-time inspection of the Station Blackout Diesel Clean Fuel Tank will be performed as part of the TMI-1 Fuel Oil Chemistry AMP. Should the one-time inspection reveal evidence of aging effects, this condition will be entered into the corrective action process for resolution. Multilevel sampling, tank bottom draining, cleaning, and internal inspection of the 550 gallon Station Blackout Diesel Fuel Day Tank is not periodically performed at TMI-1. This tank is integral* to the routine operation of the Station Blackout Diesel and is filled with fuel oil that has been previously analyzed within its managed source tank, the Station Blackout Diesel Fuel Storage Tank. The fuel oil within the Day Tank is recirculated to the Station Blackout Diesel Fuel Storage Tank quarterly to prevent the accumulation of contaminants and water and sediment. Therefore, the periodic draining of water and sediment from the bottom of the Day Tank, and, the periodic draining, cleaning, and internal inspections are not necessary. To confirm the absence of any significant aging effects, a one-time inspection of the Station Blackout Diesel Day Tank will be performed as part of the TMI-1 Fuel Oil Chemistry AMP. Should the one-time inspection reveal evidence of aging effects, this condition will be entered into the corrective action process for resolution. By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program" program element. The staff noted that it is not clear why these tanks can't be periodically drained, cleaned, and periodically inspected and the extent of UT examination of the tank bottoms. In RAI B.2.1.16-2, dated September 29, 2008, the staff requested that the applicant provide additional information concerning the design features and the extent of the UT inspection planned for the tank bottoms. In its response to the RAI dated October 20, 2008, the applicant provided design details for the 550 gallon diesel fuel oil day tank and the 7.3 gallon diesel clean fuel oil tank. The applicant stated that design features, such as manholes or hatches do not exist in these tanks, and do not allow them to be readily inspected and cleaned or to allow multilevel sampling from these tanks. The applicant stated it will rely on a one-time volumetric examination of the exterior of the bottoms of these tanks to verify loss of material has not occurred in these tanks. The applicant stated that an internal Visual inspection may be substituted in place of the volumetric inspection and if loss of material is detected by either external volumetric inspection or interior visual inspection, the finding will be entered into the corrective action process which will identify additional actions necessary to manage the degradation through the period of extended operation. Based on its review, the staff finds the applicant's response to RAI B.2.1.16-2 acceptable and also the exception to the GALL Report acceptable because 1) volumetric inspections of the exterior of the tank bottoms, or as an option, interior visual inspection of these tanks, will detect tank wall degradation prior to loss of the intended function of these tanks; and 2) actions will be identified and executed through the corrective action process to assure the intended function of the tanks will be maintained through the period of extended operation if degradation is found. Exception

4. The LRA states an exception to the GALL Report as follows: NUREG-1801 requires periodic multilevel sampling of tanks in accordance with the manual sampling standards of ASTM D 4057-95 (2000). TMI-1 has not committed to ASTM D 4057-95 (2000) for manual sampling standards:

3-76 The Diesel Fire Pump 350 gallon fuel oil storage tank and the Emergency Diesel Generator 550 gallon fuel oil day tank samples are single point samples obtained from the tank drain line locatedoff of the bottom of the tank. This sample is not considered a multilevel sample as described in ASTM D 4057. Although the actual sample location is a single point taken from the tank bottom, the lower sample elevation is more likely to contain contaminants and water and sediment which tend to settle in the tank, thus making this a conservative and effective sampling location for fuel oil contaminants. Operating experience from January 2000 through June 2007 has shown that this sample method has yielded consistently acceptable sample results.The 50,000 gallon fuel oil storage tank samples are obtained from an inline sample connection located off of the tank outlet piping. This sample is not considered a multilevel sample as described in ASTM D 4057. Sampling of the tank is performed after recirculating the tank contents which promotes tank mixing and purging of the recirculation and sample piping. Although the actual sample draw off location is off of the tank outlet which is towards the bottom of the tank, the lower sample elevation is more likely to contain contaminants and water and sediment which tend to settle in the tank, thus making this a conservative and effective sampling location for fuel oil contaminants. Operating experience from January 2005 through July 2007 has shown that this sample method has yielded consistently acceptable sample results.By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects," and "acceptance criteria" program elements.The staff noted that it is not clear why multilevel sampling of these tanks can't be performed. In RAI B.2.1.16-3, dated September 29, 2008, the staff requested that the applicant provide additional information about the design features of these tanks.In its response to the RAI dated October 20, 2008, the applicant stated that multilevel sampling in various tanks cannot be performed because there are no practical means to access the tanks to perform the sampling such as manways and drain lines.Based on its review, the staff finds the applicant's response to RAI B.2.1.16-3 acceptable and also finds the exception to the GALL Report acceptable because 1) multilevel sampling is not practical and the samples are taken at the bottom of the tanks where contaminants tend to be the greatest, 2) a one-time inspection of these tanks, as described above, will confirm the absence of degradation of tank bottoms which would potentially be caused by water, sediment and particulate contamination, and 3) the finding will be entered into the corrective action process which will identify additional actions necessary to manage the degradation through the period of extended operation. The staffs concern described in RAI B.2.1.16-3 is resolved.Enhancements. The LRA states 12 enhancements to the GALL Report as follows: The TMI-1 Fuel Oil Chemistry AMP will be enhanced to include: The completion of full spectrum fuel oil analysis within-31 days following the addition of new fuel oil into fuel storage tanks. (Enhancement No. 1)* The determination of water and sediment in accordance with ASTM D1796-97.(Enhancement No. 2)3-77 The Diesel Fire Pump 350 gallon fuel oil storage tank and the Emergency Diesel Generator 550 gallon fuel oil day tank samples are single point samples obtained from the tank drain line located off of the bottom of the tank. This sample is not considered a multilevel sample as described in ASTM 04057. Although the actual sample location is a single point taken from the tank bottom, the lower sample elevation is more likely to contain contaminants and water and sediment which tend to settle in the tank, thus making this a conservative and effective sampling location for fuel oil contaminants. Operating experience from January 2000 through June 2007 has shown that this sample method has yielded consistently acceptable sample results. The 50,000 gallon fuel oil storage tank samples are obtained from an inline sample connection located off of the tank outlet piping. This sample is not considered a multilevel sample as described in ASTM 0 4057. Sampling of the tank is performed after recirculating the tank contents which promotes tank mixing and purging of the recirculation and sample piping. Although the actual sample draw off location is off of the tank outlet which is towards the bottom of the tank, the lower sample elevation is more likely to contain contaminants and water and sediment which tend to settle in the tank, thus making this a conservative and effective sampling location for fuel oil contaminants. Operating experience from January 2005 through July 2007 has shown that this sample method has yielded consistently acceptable sample results. By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects," and "acceptance criteria" program elements. The staff noted that it is not clear why multilevel sampling of these tanks can't be performed. In RAI B.2.1.16-3, dated September 29, 2008, the staff requested that the applicant provide additional information about the design features of these tanks. In its response to the RAI dated October 20, 2008, the applicant stated that multilevel sampling in various tanks cannot be performed because there are no practical means to access the tanks to perform the sampling such as manways and drain lines. ,Based on its review, the staff finds the applicant's response to RAI B.2.1.16-3 acceptable and also finds the exception to the GALL Report acceptable because 1) multilevel sampling is not practical and the samples are taken at the bottom of the tanks where contaminants tend to be the greatest, 2) a one-time inspection of these tanks, as described above, will confirm the absence of degradation of tank bottoms which would potentially be caused by water, sediment and particulate contamination, and 3) the finding will be entered into the corrective action process which will identify additional actions necessary to manage the degradation through the period of extended operation. The staff's concern described inRAI B.2.1.16-3 is resolved. Enhancements. The LRA states 12 enhancements to the GALL Report as follows: The TMI-1 Fuel Oil Chemistry AMP will be enhanced to include:

  • The completion of full spectrum fuel oil analysis within 31 days following the addition of new fuel oil into fuel storage tanks. (Enhancement No.1)
  • The determination of water and sediment in accordance with ASTM 01796-97. (Enhancement No.2) 3-77 The analysis for particulate contamination in new and stored fuel oil in accordance with modified ASTM D2276, Method A. (Enhancement No. 3)* The analysis for bacteria in new and stored fuel oil. (Enhancement No. 4)* The addition of biocides, stabilizers, or corrosion inhibitors as determined by fuel oil analysis activities. (Enhancement No. 5)Activities to periodically drain, clean, and inspect the 50,000 gallon fuel oil storage tank, the 550 gallon diesel generator day tanks, the 25,000 gallon station blackout diesel fuel storage tank, and the Diesel Fire Pump 350 gallon fuel oil storage tanks. (Enhancement No. 6)Activities to periodically drain water and sediment from tank bottoms for the 50,000 gallon fuel oil storage tank, the 30,000 gallon diesel generator fuel storage tank, and the Diesel Fire Pump 350 gallon fuel oil storage tanks.(Enhancement No. 7)The analysis of new oil for specific or API gravity, kinematic viscosity, and water and sediment prior to filling the 50,000 gallon fuel oil storage tank and the Diesel Fire Pump 350 gallon fuel oil storage tanks. (Enhancement No. 8)Quarterly sampling for the 550 gallon diesel generator day tanks. (EnhancementNo. 9)Sampling of new fuel oil deliveries in accordance with ASTM D 4057-95 (2000).(Enhancement No. 10)* Multilevel sampling of the Emergency Diesel Generator 30,000 gallon fuel oil storage tank and the SBO Diesel Generator 25,000 gallon fuel oil storage tank in accordance with ASTM D 4057. (Enhancement No. 11)* The use of ultrasonic techniques for determining tank bottom thicknesses should there be any evidence of loss of material due to general, pitting, crevice, and microbiologically-influenced corrosion, and fouling found during visual inspection activities. (Enhancement No. 12)By letter dated October 30, 2008, the applicant stated that the enhancements apply to the program elements as follows: Enhancement No. 1 applies to the "scope of program" and "monitoring and trending" program elements.Enhancement No. 2 applies to the "scope of program," "parametersmonitored/inspected," "detection of aging effects" and "acceptance criteria" program elements.3-78* The analysis for particulate contamination in new and stored fuel oil in accordance with modified ASTM D2276, Method A. (Enhancement No.3)
  • The analysis for bacteria in new and stored fuel oil. (Enhancement No.4)
  • The addition of biocides, stabilizers, or corrosion inhibitors as determined by fuel oil analysis activities. (Enhancement No.5)
  • Activities to periodically drain, clean, and inspect the 50,000 gallon fuel oil storage tank, the 550 gallon diesel generator day tanks, the 25,000 gallon station blackout diesel fuel storage tank, and the Diesel Fire Pump 350 gallon fuel oil storage tanks. (Enhancement No.6)
  • Activities to periodically drain water and sediment from tank bottoms for the 50,000 gallon fuel oil storage tank, the 30,000 gallon diesel generator fuel storage tank, and the Diesel Fire Pump 350 gallon fuel oil storage tanks. (Enhancement No.7)
  • The analysis of new oil for specific or API gravity, kinematic viscosity, and water and sediment prior to filling the 50,000 gallon fuel oil storage tank and the Diesel Fire Pump 350 gallon fuel oil storage tanks. (Enhancement No.8)
  • Quarterly sampling for the 550 gallon diesel generator day tanks. (Enhancement No.9)
  • Sampling of new fuel oil deliveries in accordance with ASTM D 4057-95 (2000). (Enhancement No. 10)
  • Multilevel sampling of the Emergency Diesel Generator 30,000 gallon fuel oil storage tank and the SBO Diesel Generator 25,000 gallon fuel oil storage tank in accordance with ASTM D 4057. (Enhancement No. 11)
  • The use of ultrasonic techniques for determining tank bottom thicknesses should there be any evidence of loss of material due to general, pitting, crevice, and microbiologically-influenced corrosion, and fouling found during visual inspection activities. (Enhancement No. 12) By letter dated October 30, 2008, the applicant stated that the enhancements apply to the program elements as follows:
  • Enhancement No.1 applies to the "scope of program" and "monitoring and trending" program elements.
  • Enhancement No.2 applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects" and "acceptance criteria" program elements.

3-78 Enhancement No. 3 applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects" and "acceptance criteria" program elements.Enhancement No. 4 applies to the "monitoring and trending" program element.Enhancement No. 5 applies to the "preventive actions" and "corrective actions" program elements.Enhancement No. 6 applies to the "preventive actions" and "detection of aging effects" program elements.* Enhancement No. 7 applies to the "preventive actions" program element.* Enhancement No. 8 applies to the "scope of program" and "monitoring andtrending" program elements.* Enhancement No. 9 applies to the "parameters monitored/inspected," "detection of aging effects," and "monitoring and trending" program elements.* Enhancement No. 10 applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects," and "acceptance criteria" program elements.* Enhancement No. 11 applies to the "scope of program," "parametersmonitored/inspected," "detection of aging effects," and "acceptance criteria" program elements.* Enhancement No. 12 applies to the "detection of aging-effects" program element.The applicant committed to program enhancements that will a) add fuel oil sampling activities and increase sampling frequencies, b) provide for adherence to industry sampling standards, c) provide for biocide and inhibitor additions to fuel oil if required, d) provide for draining, cleaning and inspection of fuel tanks that had not previously been subjected to these activities, and e) use ultrasonic techniques to determine loss of material of tank bottoms should evidence of loss of material be identified during visual inspection activities. Based on its review, the staff finds that these enhancements are acceptable because they provide changes to the applicant's Fuel Oil Chemistry Program so that it will conform with GALL AMP XI.M30 and they will contribute to the additional assurance that loss of material will not progress such that the intended function of the piping and tanks subjected to the AMP will be compromised through the period of extended operation. Operatinq Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.16 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.3-79* Enhancement No.3 applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects" and "acceptance criteria" program elements.

  • Enhancement No.4 applies to the "monitoring and trending" program element.
  • Enhancement No.5 applies to the "preventive actions" and "corrective actions" program elements.
  • Enhancement No.6 applies to the "preventive actions" and "detection of aging effects" program elements.
  • Enhancement No. 7 applies to the "preventive actions" program element.
  • Enhancement No. 8 applies to the "scope of program" and "monitoring and trending" program elements.
  • Enhancement No.9 applies to the "parameters monitored/inspected," "detection of aging effects," and "monitoring and trending" program elements.
  • Enhancement No.1 0 applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects," and "acceptance criteria" program elements.
  • Enhancement No. 11 applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects," and "acceptance criteria" program elements.
  • Enhancement No. 12 applies to the "detection of aging effects" program element. The applicant committed to program enhancements that will a) add fuel oil sampling activities and increase sampling frequencies, b) provide for adherence to industry sampling standards, c) provide for biocide and inhibitor additions to fuel oil if required, d) provide for draining, cleaning and inspection of fuel tanks that had not previously been subjected to these activities, and e) use ultrasonic techniques to determine loss of material of tank bottoms should evidence of loss of material be identified during visual inspection activities.

Based on its review, the staff finds that these enhancements are acceptable because they provide changes to the applicant's Fuel Oil Chemistry Program so that it will conform with GALL AMP XI.M30 and they will contribute to the additional assurance that loss of material will not progress such that the intended function of the piping and tanks subjected to the AMP will be compromised through the period of extended operation. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.16 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. 3-79 In the LRA the applicant stated that demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that loss of material due to general, pitting, crevice, and microbiologically-influenced corrosion, and fouling are being adequately managed. The staff s review of documents provided by the applicant during the onsite audit did not include results of cleaning and visual inspection of fuel oil tanks. In RAI B.2.1.16-4, dated September 29, 2008, the staff requested additional information providing documentation of the fuel oil tank cleaning and visual inspections. In its response to the RAI dated October 20, 2008, the applicant stated that only the FO-T-1 fuel oil tank was subjected to cleaning and internal visual inspection in September 2007. The applicant discovered unacceptable pitting corrosion. The pits, although small in diameter, were greater than 50% of the floor plate thickness, and were repaired in accordance with industry standard, American Petroleum Institute (API) 653 by welding patch plates over the affected areas. The applicant's AMP also provides for internal cleaning of the FO-T-1 fuel oil tank during the period of extended operation every ten years. The staff noted that all other fuel oil tanks will receive periodic cleaning and visual inspection of the tank interior or one-time external volumetric inspection of tank bottoms during the period of extended operation or prior to entering the period of extended operation. The staff finds that either volumetric inspection of exterior tank bottoms or cleaning or visual inspection of tank interiors detecting loss of material to be acceptable. Additionally, the applicant stated that indications of degradation will be entered into the corrective action process to identify actions to assure the intended function of the tanks will be maintained through the period of extended operation. The staff noted that the documentation provided by the applicant during the onsite review supported the applicant's statements regarding operating experience and confirmed that the plant-specific operating experience did not reveal any degradation not bounded by industry experience except for the severe pitting corrosion (greater than 50% through-wall) in the FO-T-1 fuel oil tank. Acceptable corrective actions have been performed by the applicant for the severe pitting corrosion discovered in the FO-T-1 fuel oil tank.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 SuDplement. LRA Section A.2.1.16, provides the applicant's UFSAR Supplement for the Fuel Oil Chemistry Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR after enhancements to the AMP are implemented. In LRA Section A.5, Commitment No. 16, the applicant committed to implement Enhancements Nos. 1 through 12 prior to the period of extended operation.The staff finds that the applicant has provided an adequate summary description of the Fuel Oil Chemistry Program as required by 10 CFR 54.21(d).Conclusion. On the basis of its review of the applicant's Fuel Oil Chemistry Program and the applicant's response to the RAI's, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exceptions and their justifications and finds that the AMP, with exceptions, is adequate to manage the aging effects for which the LRA credits it. The staff also reviewed the enhancements and 3-80 In the LRA the applicant stated that demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that loss of material due to general, pitting, crevice, and microbiologically-influenced corrosion, and fouling are being adequately managed. The staff's review of documents provided by the applicant during the onsite audit did not include results of cleaning and visual inspection of fuel oil tanks. In RAI 8.2.1.16-4, dated September 29, 2008, the staff requested additional information providing documentation of the fuel oil tank cleaning and visual inspections. In its response to the RAI dated October 20,2008, the applicant stated that only the FO-T-1 fuel oil tank was subjected to cleaning and internal visual inspection in September 2007. The applicant discovered unacceptable pitting corrosion. The pits, although small in diameter, were greater than 50% of the floor plate thickness, and were repaired in accordance with industry standard, American Petroleum Institute (API) 653 by welding patch plates over the affected areas. The applicant's AMP also provides for internal cleaning of the FO-T-1 fuel oil tank during the period of extended operation every ten years. The staff noted that all other fuel oil tanks will receive periodic cleaning and visual inspection of the tank interior or one-time external volumetric inspection of tank bottoms during the period of extended operation or prior to entering the period of extended operation. The staff finds that either volumetric inspection of exterior tank bottoms or cleaning or visual inspection of tank interiors detecting loss of material to be acceptable. Additionally, the applicant stated that indications of degradation will be entered into the corrective action process to identify actions to assure the intended function of the tanks will be maintained through the period of extended operation. The staff noted that the documentation provided by the applicant during the onsite review supported the applicant's statements regarding operating experience and confirmed that the plant-specific operating experience did not reveal any degradation not bounded by industry experience except for the severe pitting corrosion (greater than 50% through-wall) in the FO-T-1 fuel oil tank. Acceptable corrective actions have been performed by the applicant for the severe pitting corrosion discovered in the FO-T -1 fuel oil tank. The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A1.2.3.1 o. The staff finds this program element acceptable. UFSAR Supplement. LRA Section A2.1.16, provides the applicant's UFSAR Supplement for the Fuel Oil Chemistry Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR after enhancements to the AMP are implemented. In LRA Section A5, Commitment No. 16, the applicant committed to implement Enhancements Nos. 1 through 12 prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Fuel Oil Chemistry Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's Fuel Oil Chemistry Program and the applicant's response to the RAl's, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exceptions and their justifications and finds that the AMP, with exceptions, is adequate to manage the aging effects for which the LRA credits it. The staff also reviewed the enhancements and 3-80 confirmed that their implementation through Commitment No. 16, prior to the period of extended operation, would make the existing AMP consistent with the GALL AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging willbe adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.13 Reactor Vessel Surveillance Summary of Technical Information in the Application. LRA Section B.2.1.17 describes the existing Reactor Vessel Surveillance Program as being consistent with GALL AMP XI.M31, "Reactor Vessel Surveillance." TMI-1 participates in the Pressurized-Water Reactor Owners Group (PWROG) Master Integrated Reactor Vessel Surveillance Program (MIRVSP), to monitor the reactor vessel (RV) beltline materials that are projected to exceed a cumulative neutron fluence of 1 x 1017 n/cm 2 (E > 1.0 MeV) during 60 years of operation. The MIRVSP was initiated in 1977 with the seven operating B&W 177-fuel assembly plants. In 1988, six Westinghouse-,designed plants having Babcock &Wilcox-fabricated RVs joined the MIRVSP. The integrated program is feasible because of the similarity of the design and the operating characteristics of the affected plants, as required by 10 CFR Part 50, Appendix H, paragraph II.C. The purpose of the MIRVSP is to augment the existing RV surveillance programs for the participating units, and to provide a basis for sharing information between plants. The MIRVSP provides sufficient material data to meet the American Society for Testing and Materials (ASTM) Standard E 185-82 capsule requirement for monitoring RV embrittlement. The MIRVSP consists of two parts. The first is a plant-specific program. TMI-1 capsules were moved to the Crystal River-3 reactor for irradiation because the original TMI-1 capsule holder tubes were damaged. The second part of the MIRVSP consists of special research capsules designed to provide fracture toughness data on Linde 80 weld metals, which are predicted to exhibit high sensitivity to irradiation damage. The MIRVSP capsule withdrawal schedule for limiting Linde 80 weld metal heats addresses neutron fluence exposures corresponding to 60 and 80 years of operation. Appendix H to 10 CFR Part 50, "Reactor Vessel Material Surveillance Program Requirements," includes requirements to monitor changes in the fracture toughness properties of ferritic materials in the reactor vessel beltline region of light water nuclear power reactors which result from exposure of these materials to neutron irradiation and the thermal environment. Appendix H to 10 CFR Part 50 endorses American Society for Testing Materials (ASTM) Standard E 185,"Surveillance Tests for Nuclear Reactor Vessels." Appendix H states that "the design of the surveillance program and the withdrawal schedule must meet the requirements of the edition of ASTM Standard E 185 that is current on the issue date of the ASME Code to which the reactor vessel was purchased. Later editions of ASTM Standard E 185 may be used, but including only those editions through 1982." ASTM Standard E 185-82 covers procedures for monitoring the radiation-induced changes in themechanical properties of ferritic materials in the beltline of light-water cooled nuclear power reactor vessels. These practices include guidelines for designing a minimum surveillanceprogram, selecting materials, and evaluating test results.3-81 confirmed that their implementation through Commitment No. 16, prior to the period of extended operation, would make the existing AMP consistent with the GALL AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.13 Reactor Vessel Surveillance Summary of Technical Information in the Application. LRA Section B.2.1.17 describes the existing Reactor Vessel Surveillance Program as being consistent with GALL AMP XI.M31, "Reactor Vessel Surveillance." TMI-1 participates in the Pressurized-Water Reactor Owners Group (PWROG) Master Integrated Reactor Vessel Surveillance Program (MIRVSP), to monitor the reactor vessel (RV) beltline materials that are projected to exceed a cumulative neutron fluence of 1 x 10 17 n/cm 2 (E > 1.0 MeV) during 60 years of operation. The MIRVSP was initiated in 1977 with the seven operating B&W 177-fuel assembly plants. In 1988, six Westinghouse-designed plants having Babcock & Wilcox-fabricated RVs joined the MIRVSP. The integrated program is feasible because of the similarity of the design and the operating characteristics of the affected plants, as required by 10 CFR Part 50, Appendix H, paragraph II.C. The purpose of the MIRVSP is to augment the existing RV surveillance programs for the participating units, and to provide a basis for sharing information between plants. The MIRVSP provides sufficient material data to meet the American Society for Testing and Materials (ASTM) Standard E 185-82 capsule requirement for monitoring RV embrittlement. The MIRVSP consists of two parts. The first is a plant-specific program. TMI-1 capsules were moved to the Crystal River-3 reactor for irradiation because the original TMI-1 capsule holder tubes were damaged. The second part of the MIRVSP consists of special research capsules designed to provide fracture toughness data on Linde 80 weld metals, which are predicted to exhibit high sensitivity to, irradiation damage. The MIRVSP capsule withdrawal schedule for limiting Linde 80 weld metal heats addresses neutron fluence exposures corresponding to 60 and 80 years of operation. Appendix H to 10 CFR Part 50, "Reactor Vessel Material Surveillance Program Requirements," includes requirements to monitor changes in the fracture toughness properties of ferritic materials in the reactor vessel, beltline region of light water nuclear power reactors which result from exposure of these materials to neutron irradiation and the thermal environment. Appendix H to 10 CFR Part 50 endorses American Society for Testing Materials (ASTM) Standard E 185, "Surveillance Tests for Nuclear Reactor Vessels." Appendix H states that "the design of the surveillance program and the withdrawal schedule must meet the requirements of the edition of ASTM Standard E 185 that is current on the issue date of the ASME Code to which the reactor vessel was purchased. Later editions of ASTM Standard E 185 may be used, but including only those editions through 1982." ASTM Standard E 185-82 covers procedures for monitoring the radiation-induced changes in the mechanical properties of ferritic materials in the beltline of light-water cooled nuclear power reactor vessels. These practices include guidelines for designing a minimum surveillance program, selecting materials, and evaluating test results. 3-81 Staff Evaluation. The staff reviewed the applicant's claim of consistency with the GALL Report.In LRA Section B.2.1.17, "Reactor Vessel Surveillance," the applicant described its AMP to manage aging in RV beltline materials. The staff reviewed the LRA for consistency with GALL AMP XI.M31, "Reactor Vessel Surveillance." By letter dated June 11, 1991, the staff approved the basis for the MIRVSP concept (BAW-1 543, Revision 3), concluding that the program met the criteria provided by Appendix H to 10 CFR Part 50. Revision 4 to BAW-1543, issued in February 1993, updated some of the MIRVSP units'withdrawal schedules. Additional supplements to BAW-1543, Revision 4, were provided to update information, particularly regarding fluence values and withdrawal schedules. BAW-1543, Revision 4, Supplement 1 provided revised fluence values for some units and revised some withdrawal schedules to comply with the 1973 Edition of the ASTM Standard E 185, "Standard Recommended Practice for Surveillance Tests for Nuclear Reactor Vessels" (ASTM E 185-73).BAW-1543, Revision 4, Supplement 2, issued in June 1996, reflected revised fluence values and withdrawal schedules. BAW-1543, Revision 4, Supplement 3, issued in February 1999, deleted Rancho Seco, R.E. Ginna, and Zion, Units 1 and 2 from the MIRVSP. BAW-1543, Revision 4, Supplement 4, issued in April 2001, added a disposal plan for archived specimens, updated the status for various capsules, and incorporated current fluence levels. The staff approved therevised and updated information by letter dated July 31, 2001 (ML0121303741), concluding that the proposed revisions satisfied the ASTM E 185-82 standards for plants participating in the MIRVSP, with the exception of Turkey Point, Units 3 and 4. BAW-1 543, Supplement 4, Revision 5, issued in December 2003, revised withdrawal schedules for various plants, including TMI-1. By letter dated May 16, 2005 (ML051400361), the staff reviewed BAW-1 543, Revision 5, and concluded that the proposed withdrawal schedules complied with Appendix H to 10 CFR Part 50.BAW-1 543, Supplement 4, Revision 6 was submitted in December 2005, with updated fluence values and surveillance capsule insertion and withdrawal schedules. By letter dated June 28, 2007 (ML071770640), the staff concluded that the revisions were acceptable and the proposed withdrawal schedules satisfy the ASTM Standard E 185-82 for most MIRVSP plants, including TMI-1.The TMI-1 limiting material contained in Capsule TMI-2-LG2 was tested and satisfied the fifth capsule requirement of ASTM Standard E 185-82. By letter dated November 17, 2003 (ML033220292), the staff reviewed BAW-2439, "Babcock & Wilcox Owners Group Analysis of Capsule TMI2-LG2: Master Integrated Reactor Vessel Surveillance Program," and concluded that upper-shelf fracture toughness tests conducted on the welds demonstrated that RG 1.99, Revision 2 conservatively represented the data in justifying continued operation with the unit's Linde 80 weld material. Wetted surface fluence values projected for 52 effective full power year (EFPY) ranged from 1.77 x 1019 n/cm 2 to 1.971 x 1019 n/cm 2 (E > 1 MeV) for the TMI-1 beltline materials. Specimens from the TMI2-LG2 capsule received an average fast neutron fluence of 2.01 x 1019 n/cm 2 (E > 1 MeV). The fluence values from the most recent capsule withdrawn, Capsule TMI2-LG2, are very close to the projected 52 EFPY fluence values. All capsules were removed and tested to meet the test procedures and reporting requirements of ASTM Standard E 185-82. This meets the ASTM E 185-82 criterion which states that capsules may be removedwhen the capsule neutron fluence is between one and two times the limiting fluence calculated for the vessel at EOL. The staff review of upper-shelf energy (USE) and pressurized thermal shock (PTS) values in the limiting materials found that all were acceptable. Operatingq Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.17 to confirm that the plant-specific operating experience did not reveal any aging effects 3-82 Staff Evaluation. The staff reviewed the applicant's claim of consistency with the GALL Report. In LRA Section B.2.1.17, "Reactor Vessel Surveillance," the applicant described its AMP to manage aging in RV beltline materials. The staff reviewed the LRA for consistency with GALL AMP XI.M31 , "Reactor Vessel Surveillance." By letter dated June 11, 1991, the staff approved the basis for the MIRVSP concept (BAW-1543, Revision 3), concluding that the program met the criteria provided by Appendix H to 10 CFR Part 50. Revision 4 to BAW-1543, issued in February 1993, updated some of the MIRVSP units' withdrawal schedules. Additional supplements to BAW-1543, Revision 4, were provided to update information, particularly regarding f1uence values and withdrawal schedules. BAW-1543, Revision 4, Supplement 1 provided revised fluence values for some units and revised some withdrawal schedules to comply with the 1973 Edition of the ASTM Standard E 185, "Standard Recommended Practice for Surveillance Tests for Nuclear Reactor Vessels" (ASTM E 185-73). BAW-1543, Revision 4, Supplement 2, issued in June 1996, reflected revised fluance values and withdrawal schedules. BAW-1543, Revision 4, Supplement 3, issued in February 1999, deleted Rancho Seco, R.E. Ginna, and Zion, Units 1 and 2 from the MIRVSP. BAW-1543, Revision 4, Supplement 4, issued in April 2001, added a disposal plan for archived specimens, updated the status for various capsules, and incorporated current fluence levels. The staff approved the revised and updated information by letter dated July 31,2001 (ML0121303741), concluding that the proposed revisions satisfied the ASTM E 185-82 standards for plants participating in the MIRVSP, with the exception of Turkey Point, Units 3 and 4. BAW-1543, Supplement 4, Revision 5, issued in December 2003, revised withdrawal schedules for various plants, including TMI-1. By letter dated May 16, 2005 (ML051400361), the staff reviewed BAW-1543, Revision 5, and concluded that the proposed withdrawal schedules complied with Appendix H to 10 CFR Part 50. BAW-1543, Supplement 4, Revision 6 was .submitted in December 2005, with updated fluence values and surveillance capsule insertion and withdrawal schedules. By letter dated June 28, 2007 (ML071770640), the staff concluded that the revisions were acceptable and the proposed withdrawal schedules satisfy the ASTM Standard E 185"-82 for most MIRVSP plants, including TMI-1. The TMI-1 limiting material contained in Capsule TMI-2-LG2 was tested and satisfied the fifth capsule requirement of ASTM Standard E 185-82. By letter dated November 17,2003 (ML033220292), the staff reviewed BAW-2439, "Babcock & Wilcox Owners Group Analysis of Capsule TMI2-LG2: Master Integrated Reactor Vessel Surveillance Program," and concluded that upper-shelf fracture toughness tests conducted on the welds demonstrated that RG 1.99, Revision 2 conservatively represented the data in justifying continued operation with the unit's Linde 80 weld material. Wetted surface fluence values projected for 52 effective full power year (EFPY) ranged from 1.77 x 10 19 n/cm 2 to 1.971 x 10 19 n/cm 2 (E > 1 MeV) for the TMI-1 beltline materials. Specimens from the TMI2-LG2 capsule received an average fast neutron f1uence of 2.01 x 10 19 n/cm 2 (E > 1 MeV). The fluence values from the most recent capsule withdrawn, Capsule TMI2-LG2, are very close to the projected 52 EFPY fluence values. All capsules were removed and tested to meet the test procedures and reporting requirements of ASTM Standard E 185-82. This meets the ASTM E 185-82 criterion which states that capsules may be removed when the capsule neutron fluence is between one and two times the limiting fluence calculated for the vessel at EOL. The staff review of upper-shelf energy (USE) and pressurized thermal shock (PTS) values in the limiting materials found that all were acceptable. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.17 to confirm that the plant-specific operating experience did not reveal any aging effects 3-82 not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant provided the following information related to operating experience: (1) The integrated reactor vessel material surveillance program was designed when the surveillance capsule holder tubes in a number of B&W reactors were damaged and could not be repaired without a complex and expensive repair program and considerable radiation exposure to personnel. For these plants, including TMI-1, the original Reactor Vessel Surveillance Program could not provide sufficient material data and dosimetry to monitor embrittlement; therefore, the integrated program was developed. The purpose of the MIRSVP is to augment the existing Reactor Vessel Surveillance Programs for the participating units and to provide a basis for sharing information between plants. The integrated program is feasible because of the similarity of the design and operating characteristics of the affected plants, as required by 10 CFR Part 50, Appendix H, paragraph II.C. The integrated program provides sufficient material data to meet the ASTM E 185-82 capsule program requirement for monitoring embrittlement. (2) The Nuclear Regulatory Commission (NRC) staff evaluated the basis for the integrated program concept, determined the MIRVSP to be acceptable, and approved TR BAW-1543 (NP), Revision 3, by letter dated June 11, 1991. This letter concluded that theprogram met the applicable criteria from 10 CFR Part 50, Appendix H, "Reactor Vessel Material Surveillance Program Requirements." (3) TR BAW-1 543 (NP), Revision 4, issued in February 1993, updated some of the units'withdrawal schedules. TR BAW-1 543 (NP), Revision 4, Supplement 1 reflected revised fluence values for some units and revised some withdrawal schedules to comply with the 1973 Edition of American Society for Testing and Materials (ASTM) Standard E 185,"Standard Recommended Practice for Surveillance Tests for Nuclear Reactor Vessels" (ASTM E 185-73). It was anticipated that future updates to TR BAW-1 543 (NP) wouldonly involve changes to the Revision 4 Supplement. Supplement 2, issued in June 1996, reflected revised fluence values and the revised withdrawal schedules. Supplement 3, issued in February 1999, deleted Rancho Seco, R. E. Ginna, and Zion, Units 1 and 2, from the program. In addition, it updated the capsule status and the peak EOL fluences for several plants. Supplement 4, issued in May 2002, incorporated the disposal plan for stored capsules, updated the status for various capsules, and incorporated current fluence levels.(4) Supplement 5 was issued in December 2003 because the previous supplement included a commitment regarding Capsules OCI -D and OC3-F; however, that commitment could not be met because these capsules could not be removed from Crystal River, Unit 3. The NRC staff approved the revised withdrawal schedules for Oconee, Units 1, 2, and 3, and Three Mile Island, Unit 1 (TMI-1), in Supplement 5-A in May 2005. The NRC staff found that each of these plants met the capsule withdrawal schedule requirements of the 1982 Edition of ASTM Standard E 185 (ASTM E 185-82), even though the original capsuleswere not going to be withdrawn and tested for Oconee, Units 2 and 3, and TMI-1, because there were other capsules within the MIRVSP that contained the same limiting material for the subject plants that would be withdrawn and tested and, therefore, would satisfy the requirements of ASTM Standard E 185-82.3-83 not bounded by the GAll Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GAll Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GAll Report. The applicant provided the following information related to operating experience: (1) The integrated reactor vessel material surveillance program was designed when the surveillance capsule holder tubes in a number of B&W reactors were damaged and could not be repaired without a complex and expensive repair program and considerable radiation exposure to personnel. For these plants, including TMI-1, the original Reactor Vessel Surveillance Program could not provide sufficient material data and dosimetry to monitor embrittlement; therefore, the integrated program was developed. The purpose of the MIRSVP is to augment the existing Reactor Vessel Surveillance Programs for the participating units and to provide a basis for sharing information between plants. The integrated program is feasible because of the similarity of the design and operating characteristics of the affected plants, as required by 10 CFR Part 50, Appendix H, paragraph II.C. The integrated program provides sufficient material data to meet the ASTM E 185-82 capsule program requirement for monitoring embrittlement. (2) The Nuclear Regulatory Commission (NRC) staff evaluated the basis for the integrated program concept, determined the MIRVSP to be acceptable, and approved TR BAW-1543 (NP), Revision 3, by letter dated June 11, 1991. This letter concluded that the program met the applicable criteria from 10 CFR Part 50, Appendix H, "Reactor Vessel Material Surveillance Program Requirements." (3) TR BAW-1543 (NP), Revision 4, issued in February 1993, updated some of the units' withdrawal schedules. TR BAW-1543 (NP), Revision 4, Supplement 1 reflected revised fluence values for some units and revised some withdrawal schedules to comply with the 1973 Edition of American Society for Testing and Materials (ASTM) Standard E 185, "Standard Recommended Practice for Surveillance Tests for Nuclear Reactor Vessels" (ASTM E 185-73). It was anticipated that future updates to TR BAW-1543 (NP) would only involve changes to the Revision 4 Supplement. Supplement 2, issued in June 1996, reflected revised fluence values and the revised withdrawal schedules. Supplement 3, issued in February 1999, deleted Rancho Seco, R. E. Ginna, and Zion, Units 1 and 2, from the program. In addition, it updated the capsule status arid the peak EOl fluences for several plants. Supplement 4, issued in May 2002, incorporated the disposal plan for stored capsules, updated the status for various capsules, and incorporated current fluence levels. (4) Supplement 5 was issued in December 2003 because the previous supplement included a commitment regarding Capsules OC1-D and OC3-F; however, that commitment could not be met because these capsules could not be removed from Crystal River, Unit 3. The NRC staff approved the revised withdrawal schedules for Oconee, Units 1, 2, and 3, and Three Mile Island, Unit 1 (TMI-1), in Supplement 5-A in May 2005. The NRC staff found that each of these plants met the capsule withdrawal schedule requirements of the 1982 Edition of ASTM Standard E 185 (ASTM E 185-82), even though the original capsules were not going to be withdrawn and tested for Oconee, Units 2 and 3, and TMI-1, because there were other capsules within ,the MIRVSP that contained the same limiting material for the subject plants that would be withdrawn and tested and, therefore, would satisfy the requirements of ASTM Standard E 185-82. 3-83 (5) Supplement 6 was submitted in December 2005 to provide updates to fluence values and to the surveillance capsule insertion and withdrawal schedules. The NRC issued Draft Safety Evaluation Report for Supplement 6 in May 2007 for comment, and in it indicated that the revised capsule insertion and withdrawal schedules are acceptable. Therefore, the MIRVSP continues to meet the requirements of 10 CFR Part 50, Appendix H and the capsule withdrawal schedule requirements of ASTM E 185-82. The operating experience of the Reactor Vessel Surveillance Program did not show any adverse trend in performance. Problems identified would not cause significant impact to the safe operation of the plant, and adequate corrective actions were taken to prevent recurrence. Periodic self-assessments of the program are performed to identify the areas that need improvement to maintain the quality performance of the program.The applicant stated that the operating experience of the Reactor Vessel Surveillance Program did not show any adverse trend in performance and that problems identified would not cause significant impact to the safe operation of the plant, and adequate corrective actions were taken to prevent recurrence. Based on its review, the staff finds that the evaluation of operating experience for this AMP demonstrates that the proposed Reactor Vessel Surveillance Program is capable of managing the reduction of fracture toughness of the reactor vessel beltline materials due to neutron embrittlement. 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. LRA Section A.2.1.17 provides the applicant's UFSAR Supplement for the Reactor Vessel Surveillance Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms with to the staff's recommended UFSAR Supplement guidance found in the SRP-LR.In LRA Section A.5, Commitment No. 17, the applicant committed to implementation of the enhancements related to the cavity dosimetry exchange schedule. The program will also be enhanced to clarify that, if future plant operations exceed the limitations or bounds specified in Regulatory Position 1.3 of RG 1.99, Rev. 2, the impact of plant operation changes on the extent ofreactor vessel embrittlement will be evaluated and the NRC will be notified.The staff finds that the applicant has provided an adequate summary description of the Reactor Vessel Surveillance Program as required by 10 CFR 54.21(d).Conclusion. On the basis of its review of the applicant's Reactor Vessel Surveillance Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3-84 (5) Supplement 6 was submitted in December 2005 to provide updates to fluence values and to the surveillance capsule insertion and withdrawal schedules. The NRC issued Draft Safety Evaluation Report for Supplement 6 in May 2007 for comment, and in it indicated that the revised capsule insertion and withdrawal schedules are acceptable. Therefore, the MIRVSP continues to meet the requirements of 10 CFR Part 50, Appendix H and the capsule withdrawal schedule requirements of ASTM E 185-82. The operating experience of the Reactor Vessel Surveillance Program did not show any adverse trend in performance. Problems identified would not cause significant impact to the safe operation of the plant, and adequate corrective actions were taken to prevent recurrence. Periodic self-assessments of the program are performed'to identify the areas that need improvement to maintain the quality performance of the program. The applicant stated that the operating experience of the Reactor Vessel Surveillance Program did not show any adverse trend in performance and that problems identified would not cause significant impact to the safe operation of the plant, and adequate corrective actions were taken to prevent recurrence. Based on its review, the staff finds that the evaluation of operating experience for this AMP demonstrates that the proposed Reactor Vessel Surveillance Program is capable of managing the reduction of fracture toughness of the reactor vessel beltline materials due to neutron embrittlement. The staff confirmed that the "Operating Experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1 O. The staff finds this program element acceptable. UFSAR Supplement. LRA Section A.2.1 17 provides the applicant's UFSAR Supplement for the Reactor Vessel Surveillance Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms with to the staff's recommended UFSAR Supplement guidance found in the SRP-LR. In LRA Section A.5, Commitment No. 17, the applicant committed to implementation of the enhancements related to the cavity dosimetry exchange schedule. The program will also be enhanced to clarify that, if future plant operations exceed the limitations or bounds specified in Regulatory Position 1.3 of RG 1.99, Rev. 2, the impact of plant operation changes on the extent of reactor vessel embrittlement will be evaluated and the NRC will be notified. The staff finds that the applicant has provided an adequate summary description of the Reactor Vessel Surveillance Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's Reactor Vessel Surveillance Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21 (d). 3-84 3.0.3.2.14 One-Time Inspection Summary of Technical Information in the Application. LRA Section B.2.1.18 describes the newOne-Time Inspection Program as being consistent, with an exception, to GALL AMP XI.M32,"One-Time Inspection." The applicant stated that the program will a) confirm the effectiveness of the Water Chemistry Program to mitigate the loss of material, cracking, and reduction of heat transfer aging effects for steel, stainless steel, copper alloy, nickel alloy, and aluminum alloy in treated water, steam, and reactor coolant environments; b) confirm the effectiveness of the Fuel Oil Chemistry Program to mitigate the loss of material aging effect for steel, stainless steel, and copper alloy in a fuel oil environment; c) confirm the effectiveness of the Lubricating Oil Analysis Program to mitigate the loss of material and the reduction of heat transfer aging effects for steel, stainless steel, copper alloy, and aluminum alloy in a lubricating oil environment; and d) confirm the loss of material aging effect is not significant for stainless steel and copper alloy in an air and gas -wetted environment. The applicant also stated that the program includes determination of sample size, identification of inspection locations, determination of examination techniques, and evaluation of the need for follow-up examinations. The applicant further stated that if evidence of an aging effects is revealed by a one-time inspection, engineering evaluation of the inspection results will identify appropriate corrective actions.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the applicant's basis document for the program, together with the inspection sample basis document, proposed implementing procedures, and other supporting documentation related to the program. The staff reviewed the exception to determine whether the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it.In comparing the elements in the applicant's program to those in GALL AMP XI.M32, the staffdetermined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent, with an exception. Exception. The LRA states an exception to the GALL Report as follows: NUREG-1801 specifies in XI.M32 the 2001 ASME Section Xl B&PV Code, including the 2002 and 2003 Addenda for Subsections IWB, IWC, and IWD. The TMI-1 ISI Program Plan for the third ten-year inspection interval effective from April 20, 2001 through April 19, 2011, approved per 10 CFR 50.55a, is based on the 1995 ASME Section Xl B&PV Code, including 1996 addenda. The next 120-month inspection interval for TMI-1 will incorporate the requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a twelve months before the start of the inspection interval.In RAI B.2.1.18-1, dated October 7, 2008, the staff requested that the applicant provide additional information concerning the code edition referenced by the applicant that was previously approved under 10 CFR 50.55a for the ten-year interval. Additionally, the staff notified the applicant that the stated exception should not be identified as such because no exception is needed for requirements found in the 2001 edition, but not in the 1995 edition of the code. The staff requested that the applicant provide additional information to indicate agreement or to provide justification if the applicant disagreed with the staff's finding.3-85 3.0.3.2.14 One-Time Inspection Summary of Technical Information in the Application. LRA Section B.2.1.18 describes the new One-Time Inspection Program as being consistent, with an exception, to GALL AMP XI.M32, "One-Time Inspection." The applicant stated that the program will a) confirm the effectiveness of the Water Chemistry Program to mitigate the loss of material, cracking, and reduction of heat transfer aging effects for steel, stainless steel, copper alloy, nickel alloy, and aluminum alloy in treated water, steam, and reactor coolant environments; b) confirm the effectiveness of the Fuel Oil Chemistry Program to mitigate the loss of material aging effect for steel, stainless steel, and copper alloy in a fuel oil environment; c) confirm the effectiveness of the Lubricating Oil Analysis Program to mitigate the loss of material and the reduction of heat transfer aging effects for steel, stainless steel, copper alloy, and aluminum alloy in a lubricating oil environment; and d) confirm the loss of material aging effect is not significant for stainless steel and copper alloy in an air and gas -wetted environment. The applicant also stated that the program includes determination of sample size, identification of inspection locations, determination of examination techniques, and evaluation of the need for follow-up examinations. The applicant further stated that if evidence of an aging effects is revealed by a one-time inspection, engineering evaluation of the inspection results will identify appropriate corrective actions. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the applicant's basis document for the program, together with the inspection sample basis document, proposed implementing procedures, and other supporting documentation related to the program. The staff reviewed the exception to determine whether the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in GALL AMP XI.M32, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent, with an exception. Exception. The LRA states an exception to the GALL Report as follows: NUREG-1801 specifies in XI.M32 the 2001 ASME Section XI B&PV Code, including the 2002 and 2003 Addenda for Subsections IWB, IWC, and IWD. The TMI-1 lSI Program Plan for the third ten-year inspection interval effective from April 20, 2001 through April 19, 2011, approved per 10 CFR 50.55a, is based on the 1995 ASME Section XI B&PV Code, including 1996 addenda. The next 120-month inspection interval for TMI-1 will incorporate the requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a twelve months before the start of the inspection interval. In RAI B.2.1.18-1, dated October 7,2008, the staff requested that the applicant provide additional information concerning the code edition referenced by the applicant that was previously approved under 10 CFR 50.55a for the ten-year interval. Additionally, the staff notified the applicant that the stated exception should not be identified as such because no exception is needed for requirements found in the 2001 edition, but not in the 1995 edition of the code. The staff requested that the applicant provide additional information to indicate agreement or to provide justification if the applicant disagreed with the staff's finding. 3-85 In its response to the RAI dated October 30, 2008, the applicant stated that a formal exception to the ASME code version listed in the GALL Report is not required since the code edition used for the program had been previously approved under 10 CFR 50.55a for the current ten-year ISI interval. The applicant revised LRA Section B.2.1.18 to delete the previously stated exception to the GALL Report.Based on its review, the staff finds the applicant's response to RAI B.2.1.18-1 acceptable because the applicant agreed with the staff's finding that differences in ASME Code Section XI editions need not be identified as exceptions to the GALL Report and because the applicant deleted the exception from the LRA. The staffs concern described in RAI B.2.1.18-1 is resolved.Operatingq Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.18 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant stated that the One-Time Inspection Program applies to potential aging effects for which current operating experience does not indicate the need for an AMP. The applicant also stated that the examinations performed in the One-Time Inspection program are consistent with industry practice and that site-specific operating experience does exist related to the effectiveness of NDE techniques at identifying, confirming and quantifying aging effects. The applicant providedthree examples of site-specific operating experience to demonstrate effectiveness of examination techniques used in the One-Time Inspection AMP.(1) The applicant stated that in October 2004 ultrasonic testing (UT) of a pipe found wall thickness was below the nominal manufacturing tolerance of 87%. The applicant stated that an engineering review for operability concluded that the as-found wall thickness was greater than the minimum code requirement and that at the maximum predicted corrosion rate the pipe's wall thickness would continue to be above the minimum requirement for several refueling cycles. The applicant stated that future re-inspection was implemented to ensure that a conservative design margin was maintained prior to replacement of the pipe.(2) The applicant stated that in November 2005, UT pipe thickness inspections found that a pipe's wall thickness had been reduced. The applicant stated that an engineering review for operability concluded that the as-found wall thickness provided a safety factor of 10 and adequate corrosion margin until the next refueling outage, at which time the thinned pipe was scheduled to be replaced. (3) The applicant stated that in November 2001, an IS[ visual examination (VT-1) found cracking on the high pressure injection/ makeup nozzle thermal sleeve. The applicant stated that an engineering review for operability concluded that the identified crack in the thermal sleeve was very unlikely to propagate and that code requirements would continue to be met through the next operating cycle, after which appropriate corrective actions were taken.3-86 In its response to the RAI dated October 30, 2008, the applicant stated that a formal exception to the ASME code version listed in the GALL Report is not required since the code edition used for the program had been previously approved under 10 CFR 50.55a for the current ten-year 151 interval. The applicant revised LRA Section B.2.1.18 to delete the previously stated exception to the GALL Report. . Based on its review, the staff finds the applicant's response to RAI B.2.1.18-1 acceptable because the applicant agreed with the staffs finding that differences in ASME Code Section XI editions need not be identified as exceptions to the GALL Report and because the applicant deleted the exception from the LRA. The staffs concern described in RAI B.2.1.18-1 is resolved. Operating Experience. The staff reviewed the operating experience provided in LRA Section* B.2.1.18 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The applicant stated that the One-Time Inspection Program applies to potential aging effects for which current operating experience does not indicate the need for an AMP. The applicant also stated that the examinations performed in the One-Time Inspection program are consistent with industry practice and that site-specific operating experience does exist related to the effectiveness of NDE techniques at ,identifying, confirming and quantifying aging effects. The applicant provided three examples of site-specific operating experience to demonstrate effectiveness of examination techniques used in the One-Time Inspection AMP. (1) The applicant stated that in October 2004 ultrasonic testing (UT) of a pipe found wall thickness was below the nominal manufacturing tolerance of 87%. The applicant stated that an engineering review for operability concluded that the as-found wall thickness was greater than the minimum code requirement and that at the maximum predicted corrosion rate the pipe's wall thickness would continue to be above the minimum requirement for several refueling cycles. The applicant stated that future re-inspection was implemented to ensure that a conservative design margin was maintained prior to replacement of the pipe. (2) The applicant stated that in November 2005, UT pipe thickness inspections found that a pipe's wall thickness had been reduced. The applicant stated that an engineering review for operability concluded that the as-found wall thickness provided a safety factor of 10 and adequate corrosion margin until the next refueling outage, at which time the thinned pipe was scheduled to be replaced. (3) The applicant stated that in November 2001, an 151 visual examination (VT-1) found cracking on the high pressure injection/ makeup nozzle thermal sleeve. The applicant stated that an engineering review for operability concluded that the identified crack in the thermal sleeve was very unlikely to propagate and that code requirements would continue to be met through the next operating cycle, after which appropriate corrective actions were taken. 3-86 The staff noted that the examples provide confirmation that the applicant's inspection methodology is capable of detecting the aging effects of interest, and the applicant's process of performing operability evaluations of degraded conditions appears to be appropriate and to result in acceptable corrective actions being taken prior to loss of component intended function.In addition to these examples, the staff reviewed the applicant's operating experience discussion provided in the applicant's license renewal program basis document binder for the One-Time Inspection Program. The staff also reviewed additional selected corrective ARs related to examination methodology used in the AMP and interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. Based on its review, the staff finds (1) that the OE for this AMP demonstrates that the proposedOne-Time Inspection Program is capable of achieving its objective of confirming effectiveness of the applicant's Water Chemistry program, Fuel Oil Chemistry program, and Lubricating Oil Analysis program, and of detecting loss of material in stainless steel or copper alloy exposed to an air and gas -wetted environment, and (2) that the applicant's past corrective actions are consistent with appropriate corrective actions being taken through implementation of this program.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. LRA Section A.2.1.18 provides the applicant's UFSAR Supplement for the One-Time Inspection Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms with to the staff's recommended UFSAR Supplement guidance found in the SRP-LR.In LRA Section A.5, Commitment No. 18, the applicant committed to implementation of the One-Time Inspection Program for aging management of applicable components prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the One-Time Inspection Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's One-Time Inspection Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exception and the applicant's response to the RAI, and finds that no formal exception to the GALL Report was required, and also finds that the AMP is adequate to manage the aging effects for which the LRA credits it. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.15 Buried Piping and Tanks Inspection Summary of Technical Information in the Application. LRA Section B.2.1.20 describes the applicant's existing Buried Piping and Tanks Inspection Program as being consistent, with exceptions and enhancements, to GALL AMP XI.M34, "Buried Piping and Tanks Inspection." 3-87 The staff noted that the examples provide confirmation that the applicant's inspection methodology is capable of detecting the aging effects of interest, and the applicant's process of performing operability evaluations of degraded conditions appears to be appropriate and to result in acceptable corrective actions being taken prior to loss of component intended function. In addition to these examples, the staff reviewed the applicant's operating experience discussion provided in the applicant's license renewal program basis document binder for the One-Time Inspection Program. The staff also reviewed additional selected corrective ARs related to examination methodology used in the AMP and interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. Based on its review, the staff finds (1) that the OE for this AMP demonstrates that the proposed One-Time Inspection Program is capable of achieving its objective of confirming effectiveness of the applicant's Water Chemistry program, Fuel Oil Chemistry program, and Lubricating Oil AnalysiS program, and of detecting loss of material in stainless steel or copper alloy exposed to an air and gas -wetted environment, and (2) that the applicant's past corrective actions are consistent with appropriate corrective actions being taken through implementation of this program. The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1 O. The staff finds this program element acceptable. UFSAR Supplement. LRA Section A.2.1.18 provides the applicant's UFSAR Supplement for the One-Time Inspection Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms with to the staff's recommended UFSAR Supplement guidance found in the SRP-LR. In LRA Section A.5, Commitment No. 18, the applicant committed to implementation of the Time Inspection Program for aging management of applicable components prior to the period of . extended operation. The staff finds that the applicant has provided an adequate summary description of the One-Time Inspection Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's One-Time Inspection Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exception and the applicant's response to the RAI, and finds that no formal exception to the GALL Report was required, and also finds that the AMP is adequate to manage the aging effects for which the LRA credits it. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.15 Buried Piping and Tanks Inspection Summary of Technical Information in the Application. LRA Section 8.2.1.20 describes the applicant's existing Buried Piping and Tanks Inspection Program as being consistent, with exceptions and enhancements, to GALL AMP XI.M34, "Buried Piping and Tanks Inspection." 3-87 The applicant stated that the program provides preventive measures to mitigate corrosion, and periodic inspection to manage the effects of corrosion on the pressure-retaining capacity of buried steel piping and tanks.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exceptions and enhancements to determine whether the AMP, with the exceptions and enhancements, is adequate to manage the aging effects for which the LRA credits it.In comparing the elements in the applicant's program to those in GALL AMP XI.M34, the staff determined that the program elements for which the applicant claimed consistency with the GALL Report, are consistent. Exception

1. The LRA states an exception to the GALL Report as follows: NUREG-1801, Section XI.M34 Buried Piping and Tanks Inspection aging management program scope only includes buried steel piping and components.

However TMI-1 also includes stainless steel in their buried piping program that will be managed as part of this aging management program.By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program," "preventive actions," and "acceptance criteria" program elements.The staff noted that there is no program in the GALL Report that provides for inspection of buried stainless steel pipe and that the GALL Report recommends a plant specific program to manage loss of material for stainless steel piping exposed to soil. The staff also noted that the inspection methods used for buried cast iron, carbon steel and concrete-coated steel are applicable to buried stainless steel piping as well. The staff noted that buried stainless steel piping is more resistant to pitting and crevice corrosion than carbon steels and other materials addressed in GALL AMP XI.M34 when exposed to soil and that a visual inspection of the buried stainless steel piping will detect unacceptable loss of material.Based on its review, the staff finds this exception to the GALL Report is acceptable because opportunistic or focused inspections will detect unacceptable loss of material of buried stainless steel piping, piping elements, and piping components, through the period of extended operation. Exception

2. The LRA states an exception to the GALL Report as follows: NUREG-1801, Section XI.M34 Buried Piping and Tanks Inspection aging management program relies on preventive measures such as coatings and wrappings.

However portions of buried stainless steel piping may not be coated or wrapped. Inspections of buried piping that is not wrapped will inspect for loss of material due to general, pitting, crevice, and microbiologically-influenced corrosion. By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program," "preventive actions," and "acceptance criteria" program elements.Based on its review, the staff finds this exception to the GALL Report acceptable because stainless steel pipes that are not wrapped or coated 1) are more resistant to general, pitting, crevice, and microbiologically-influenced corrosion in soil environments than carbon steel and 3-88 The applicant stated that the program provides preventive measures to mitigate corrosion, and periodic inspection to manage the effects of corrosion on the pressure-retaining capacity of buried steel piping and tanks. . Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exceptions and enhancements to determine whether the AMP, with the exceptions and enhancements, is adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in GALL AMP XI.M34, the staff determined that the program elements for which the applicant claimed consistency with the GALL Report, are consistent. Exception

1. The LRA states an exception to the GALL Report as follows: NUREG-1801, Section XI.M34 Buried Piping and Tanks Inspection aging management program scope only includes buried steel piping and components.

However TMI-1 also includes stainless steel in their buried piping program that will be managed as part of this aging management program. By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program;" "preventive actions," and "acceptance criteria" program elements. The staff noted that there is no program in the GALL Report that provides for inspection of buried stainless steel pipe and that the GALL Report recommends a plant specific program to manage loss of material for stainless steel piping exposed to soil. The staff also noted that the inspection methods used for buried cast iron, carbon steel and concrete,.coated steel are applicable to buried stainless steel piping as well. The staff noted that buried stainless steel piping is more resistant to pitting and crevice corrosion than carbon steels and other materials addressed in GALL AMP XI. M34 when exposed to soil and that a visual inspection of the buried stainless steel piping will detect unacceptable loss of material. Based on its review, the staff finds this exception to the GALL Report is acceptable because opportunistic or focused inspections will detect unacceptable loss of mc;lterial of buried stainless steel piping, piping elements, and piping components, through the period of extended operation. Exception

2. The LRA states an exception to the GALL Report as follows: NUREG-1801, Section XI.M34 Buried Piping and Tanks Inspection aging management program relies on preventive measures such as coatings and wrappings.

However portions of buried stainless steel piping may not be coated or wrapped. Inspections of buried piping that is not wrapped will inspect for loss of material due to general, pitting, crevice, and microbiologically-influenced corrosion. By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program," "preventive actions," and "acceptance criteria" program elements. Based on its review, the staff finds this exception to the GALL Report acceptable because stainless steel pipes that are not wrapped or coated 1) are more resistant to general, pitting, crevice, and microbiologically-influenced corrosion in soil environments than carbon steel and 3-88 cast iron pipes; and 2) will be subjected to the same inspection activities as buried carbon steel and cast iron piping and that these activities are capable of detecting the aging effect of loss of material for stainless steel piping.Exception

3. The LRA states an exception to the GALL Report as follows: NUREG-1801, Section XI.M34 Buried Piping and Tanks Inspection aging management program recommends that opportunistic or focused inspections of the external surfaces of buried components be performed.

Internal inspection and UT of the buried Diesel Generator Fuel Storage 30,000 Gallon Tank wall will be used in lieu of inspection of the external surface of this tank. This internal surface visual inspection and UT examination of the tank wall will provide an alternate means to monitor the tank's pressure retaining ability.By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects," and "acceptance criteria" program elements.The staff noted that an UT examination is an acceptable method for detecting wall thinning of fuel tanks as stated in GALL AMP XI.M30. The staff finds that interior UT examination is capable of detecting loss of material in buried fuel oil tanks based on the recommendations of the GALL Report. However, the staff noted that it is not clear as to the extent and scope of the UT examinations. The staff also noted that there is a potential for degradation of a buried tank over the entire surface of the tank and that measurements of tank thickness representative of the entire tank surface need to be performed to ensure that the tank will continue to perform its intended function. In RAI B.2.1.20-1, dated September 29, 2008, the staff requested that the applicant provide additional information relating to the extent and scope of the UT measurements of the buried Diesel Generator Fuel Storage 30,000 Gallon Tank.In its response to the RAI dated October 20, 20008, the applicant stated that the diesel generator fuel storage 30,000 gallon tank will be internally inspected in accordance with the guidance for assessing tank wall thickness contained in API Standard 1631, "Interior Lining and Periodic Inspection of Underground Storage Tanks" where internal tank walls will be divided into 3 foot square sections and UT examination will be performed to measure tank thickness in the center of each 3 foot square section. The applicant further stated that if any of these UT result is less than 75% of the original wall thickness then additional UT measurements will be performed in that 3 foot square section; if the average value of these additional UT measurements is less than 75% of the original wall thickness, the applicant stated that a condition report will be initiated in accordance with plant administrative procedures. The staff finds that unacceptable loss of material will be detected using the UT examination methods of API Standard 1631. The staff reviewed API Standard 1631 and noted that Section 10.6.2 provides a requirement to install cathodic protection if UT examination determines wall thicknesses to be between 75% and 85%of the original wall thickness. The staff noted that wall thicknesses between 75% and 85% of the original wall thickness indicate active loss of material and measures should be implemented to mitigate corrosion. In RAI B.2.1.20-3, dated January 5, 2009, the staff requested that the applicant provide additional information on whether cathodic protection will be provided if wall thicknesses between 75% and 85% of the original wall thickness are detected, and if not, what measures will be taken to mitigate corrosion. 3-89 cast iron pipes; and 2) will be subjected to the same inspection activities as buried carbon steel and cast iron piping and that these activities are capable of detecting the aging effect of loss of material for stainless steel piping. Exception

3. The LRA states an exception to the GALL Report as follows: NUREG-1801, Section XI,M34 Buried Piping and Tanks Inspection aging management program recommends that opportunistic or focused inspections of the external surfaces of buried components be performed.

Internal inspection and UT of the buried Diesel Generator Fuel Storage 30,000 Gallon Tank wall will be used in lieu of inspection of the external surface of this tank. This internal surface visual inspection and UT examination of the tank wall will provide an alternate means to monitor the tank's pressure retaining ability. By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects," and "acceptance criteria" program elements. The staff noted that an UT examination is an acceptable method for detecting wall thinning of fuel tanks as stated in GALL AMP XI,M30. The staff finds that interior UT examination is capable of detecting loss of material in buried fuel oil tanks based on the recommendations of the GALL Report. However, the staff noted that it is not clear as to the extent and scope of the UT examinations. The staff also noted that there is a potential for degradation of a buried tank over the entire surface of the tank and that measurements of tank thickness representative of the entire tank surface need to be performed to ensure that the tank will continue to perform its intended function. In RAI B.2.1.20-1, "dated September 29, 2008, the staff requested that the applicant provide additional information relating to the extent and scope of the UT measurements of the buried Diesel Generator Fuel Storage 30,000 Gallon Tank. In its response to the RAI dated October 20, 20008, the applicant stated that the diesel generator fuel storage 30,000 gallon tank will be internally inspected in accordance with the guidance for assessing tank wall thickness contained in API Standard 1631, "Interior Lining and Periodic Inspection of Underground Storage Tanks" where internal tank walls will be divided into 3 foot square sections and UT examination will be performed to measure tank thickness in the center of each 3 foot square section. The applicant further stated that if any of these UT result is less than 75% of the original wall thickness then additional UT measurements will be performed in that 3 foot square section; if the average value of these additional UT measurements is less than 75% of the original wall thickness, the applicant stated that a condition report will be initiated in accordance with plant administrative procedures. The staff finds that unacceptable loss of . material will be detected using the UT examination methods of API Standard 1631. The staff reviewed API Standard 1631 and noted that Section 10.6.2 provides a requirement to install cathodic protection if UT examination determines wall thicknesses to be between 75% and 85% of the original wall thickness. The staff noted that wall thicknesses between 75% and 85% of the original wall thickness indicate active loss of material and measures should be implemented to mitigate corrosion. In RAI B.2.1.20-3, dated January 5, 2009, the staff requested that the applicant provide additional information on whether cathodic protection will be provided if wall thicknesses between 75% and 85% of the original wall thickness are detected, and if not, what measures will be taken to mitigate corrosion. 3-89 In its response to the RAI dated January 12, 2009, the applicant stated that if the average measured tank thickness is between 75% and 85% of the original thickness, an evaluation will be performed to determine if the loss of wall thickness occurred from the outside surface of the tank and that if it is determined that the loss of wall thickness occurred on the external surface, then a cathodic protection system will be installed to mitigate corrosion. Based on its review, the staff finds the applicant's responses to RAI B.2.1.20-1 and RAI B.2.1.20-3 acceptable and also finds the exception acceptable because corrosion on the external tank surface will be mitigated with cathodic protection before the minimum allowable tank thickness is exceeded and because unacceptable loss of wall thickness will be detected before loss of the tank intended function occurs. The staffs concerns described in RAls B.2.1.20-1 and B.2.1.20-3 are resolved.Enhancement

1. The LRA states an enhancement to the GALL Report as follows: The Buried Piping and Tanks Inspection aging management program will be enhanced to include at least one opportunistic or focused excavation and inspection of stainless steel piping and components prior to entering the period of extended operation. (Inspection activities of buried piping and components for cast iron, carbon steel, and concrete-coatedcarbon steel materials have occurred in the ten years prior to the beginning of the period of extended operation.)

Upon entering the period of extended operation, a focused inspection of an example of each of the above materials shall be performed within ten years, unlessan opportunistic inspection occurs within this ten-year period.By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects," and "acceptance criteria" program elements.The staff noted that there is no program in the GALL Report that provides for inspection of buried stainless steel pipe and that the GALL Report recommends a plant specific program to manage loss of material for stainless steel piping exposed to soil. The staff also noted that the inspectionmethods used for buried cast iron, carbon steel and concrete-coated steel are applicable to buried stainless steel as well. The staff noted that buried stainless steel piping is more resistant to pitting and crevice corrosion than carbon steels and other materials addressed in GALL AMP XI.M34 when exposed to soil and visual inspection of buried stainless steel piping will detect unacceptable loss of material.Based on its review, the staff finds this enhancement acceptable because opportunistic or focused excavations of buried stainless steel piping will provide additional assurance that loss of material will not progress such that the intended function of the piping will not be compromised through the period of extended operation. Enhancement

2. The LRA states an enhancement to the GALL Report as follows: An internal inspection and UT of the buried Diesel Generator Fuel Storage 30,000 Gallon Tank wall will be used in lieu of inspection of the external surface of this tank. This inspection will be performed within the ten-year period prior to the period of extended operation, and within ten years of entering the period of extended operation.

3-90 In its response to the RAI dated January 12, 2009, the applicant stated that if the average measured tank thickness is between 75% and 85% of the original thickness, an evaluation will be performed to determine if the loss of wall thickness occurred from the outside surface of the tank and that if it is determined that the loss of wall thickness occurred on the external surface, then a cathodic protection system will be installed to mitigate corrosion. Based on its review, the staff finds the applicant's responses to RAI B.2.1.20-1 and RAI B.2.1.20-3 acceptable and also finds the exception acceptable because corrosion on the external tank surface will be mitigated with cathodic protection before the minimum allowable tank thickness is exceeded and because unacceptable loss of wall thickness will be detected before loss of the tank intended function occurs. The staff's concerns described in RAls B.2.1.20-1 and B.2.1.20-3 are resolved. Enhancement

1. The LRA states an enhancement to the GALL Report as follows: The Buried Piping and Tanks Inspection aging management program will be enhanced to include at least one opportunistic or focused excavation and inspection of stainless steel piping and components prior to entering the period of extended operation. (Inspection activities of buried piping and components for cast iron, carbon steel, and concrete-coated carbon steel materials have occurred in the ten years prior to the beginning of the period of extended operation.)

Upon entering the period of extended operation, a focused inspection of an example of each of the above materials shall be performed within ten years, unless an opportunistic inspection occurs within this ten-year period. By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects," and "acceptance criteria" program elements. The staff noted that there is no program in the GALL Report that provides for inspection of buried stainless steel pipe and that the GALL Report recommends a plant specific program to manage loss of material for stainless steel piping exposed to soil. The staff also noted that the inspection methods used for buried cast iron, carbon steel and concrete-coated steel are applicable to buried stainless steel as well. The staff noted that buried stainless steel.piping is more resistant to pitting and crevice corrosion than carbon steels and other materials addressed in GALL AMP XI,M34 when exposed to soil and visual inspection of buried stainless steel piping will detect unacceptable loss of material. . Based on its review, the staff finds this enhancement acceptable because opportunistic or focused excavations of buried stainless steel piping will provide additional assurance that loss of material will not progress such that the intended function of the piping will not be compromised through the period of extended operation. Enhancement

2. The LRA states an enhancement to the GALL Report as follows: An internal inspection and UT of the buried Diesel Generator Fuel Storage 30,000 Gallon Tank wall will be used in lieu of inspection of the external surface of this tank. This inspection will be performed within the ten-year period prior to the period of extended operation, and within ten years of entering the period of extended operation.

3-90 By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects," and "acceptance criteria" program elements.The staff noted that this enhancement is similar to exception

  1. 2.Based on its review, the staff finds this enhancement acceptable because UT examination of buried diesel generator fuel storage 30,000 gallon tank walls will detect any wall thinning due to general, pitting and crevice corrosion providing assurance that loss of material will not progress such that the intended function of the tank will be compromised through the period of extended operation.

Operatinq Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.20 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant stated that the operating experience shows that the program is effective in managing corrosion of external surfaces of buried steel piping and tanks through objective evidence showing that loss of material due to general, pitting, crevice, and microbiologically-influenced corrosion are being adequately managed. The applicant further stated that examples of operating experience provide objective evidence that the Buried Piping and Tanks Inspection program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation. The staff noted that an opportunistic inspection was performed by the applicant on buried fire service piping and that this piping was found to be in good condition. The applicant also performed an excavation of a de-ice line between the turbine building and condensate storage tank "A" which revealed coating deterioration and corrosion of the carbon steel piping. The applicant took corrective actions and had the affected piping segments replaced. The applicant determined that the cause of the degradation was use of improper backfill material. As a result, the applicant excavated additional underground piping and found that the proper backfill was used in these areas. The staff noted that the documentation provided by the applicant during the onsite review supports the applicant's statements regarding operating experience. 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. LRA Section A.2.1.20 provides the applicant's UFSAR Supplement for the Buried Piping and Tanks Inspection Program. The staff confirmed that the applicant's UFSARSupplement summary description for this program conforms to the staff's recommended UFSARSupplement guidance found in the SRP-LR, after the enhancements are implemented. In LRA Section A.5, Commitment No. 20 the applicant committed to credit the existing Buried Piping and Tanks Inspection Program. The applicant committed to implement the enhancements related to opportunistic or focused excavation and inspection of stainless steel piping and 3-91 By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects,'! and "acceptance criteria" program elements. The staff noted that this enhancement is similar to exception

  1. 2. Based on its review, the staff finds this enhancement acceptable because UT examination of buried diesel generator fuel storage 30,000 gallon tank walls will detect any wall thinning due to general, pitting and crevice corrosion providing assurance that loss of material will not progress such that the intended function of the tank will be compromised through the period of extended operation.

Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.20 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The applicant stated that the operating experience shows that the program is effective in managing corrosion of external surfaces of buried steel piping and tanks through objective evidence showing that loss of material due to general, pitting, crevice, and influenced corrosion are being adequately managed. The applicant further stated that examples of operating experience provide objective evidence that the Buried Piping and Tanks Inspection program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation. The staff noted that an opportunistic inspection was performed by the applicant on buried fire service piping and that this piping was found to be in good condition. The applicant also performed an excavation of a de-ice line between the turbine building and condensate storage . tank "A" which revealed coating deterioration and corrosion of the carbon steel piping. The applicant took corrective actions and had the affected piping segments replaced. The applicant determined that the cause of the degradation was use of improper backfill material. As a result, the applicant excavated additional underground piping and found that the proper backfill was used in these areas. The staff noted that the documentation provided by the applicant during the onsite review supports the applicant's statements regarding operating experience. The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A1.2.3.1 O. The staff finds this program element UFSAR Supplement. LRA Section A2.1.20 provides the applicant's UFSAR Supplement for the Buried Piping and Tanks Inspection Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR, after the enhancements are implemented. In LRA Section AS, Commitment No. 20 the applicant committed to credit the existing Buried Piping and Tanks Inspection Program. The applicant committed to implement the enhancements related to opportunistic or focused excavation and inspection of stainless steel piping and 3-91 components, and internal inspection and UT of the buried diesel generator fuel storage 30,000 gallon tank wall prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Buried Piping and Tanks Inspection Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Buried Piping and Tanks Inspection Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exceptions and their justifications and finds that the AMP, with exceptions, is adequate to manage the aging effects for which it is credited. The staff also reviewed the enhancements and confirmed that their implementation through Commitment No. 20, prior to the period of extended operation, would make the existing AMP consistent with the GALL AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.16 External Surfaces Monitoring Summary of Technical Information in the Application. LRA Section B.2.1.21 describes the new External Surfaces Monitoring Program as being consistent, with an exception, with GALL AMP XI.M36, "External Surfaces Monitoring." The applicant stated that the program is credited to manage loss of material, loss of strength and hardening for components fabricated of steel, aluminum alloy, asbestos cloth, copper alloy, elastomers and stainless steel. The applicant further stated that this program will utilize visual inspections performed during system walkdowns, which may be augmented by physical manipulation when appropriate, to detect the above mentioned aging effects. The applicant clarified that this AMP is not credited for aging management for loss of material due to boric acid or for inspections of buried piping and aboveground steel tanks. The applicant further clarified that this AMP is not credited for aging management of the internal surfaces of components. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it.In comparing the elements in the applicant's program to those in GALL AMP XI.M36, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent, with an exception. Exception. The LRA states an exception to the GALL Report as follows: The NUREG-1801 aging management program XI.M36, External Surfaces Monitoring program is based on system inspections and walkdowns. This program consists of periodic visual inspections of steel components such as piping, piping components, ducting, and other components within the scope of license renewal and subject to AMR in order to manage aging effects. The program manages aging effects through visual inspection of external surfaces for evidence of material loss. Exceptions to NUREG-1 801 are: 3-92 components, and internal inspection and UT of the buried diesel generator fuel storage 30,000 gallon tank wall prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Buried Piping and Tanks Inspection Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Buried Piping and Tanks Inspection Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exceptions and their justifications and finds that the AMP, with exceptions, is adequate to manage the aging effects for which it is credited. The staff also reviewed the enhancements and confirmed that their implementation through Commitment No. 20, prior to the period of extended operation, would make the existing AMP consistent with the GALL AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLS for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.16 External Surfaces Monitoring Summary of Technical Information in the Application. LRA Section B.2.1.21 describes the new External Surfaces Monitoring Program as being consistent, with an exception, with GALL AMP XI.M36, "External Surfaces Monitoring." The applicant stated that the program is credited to manage loss of material, loss of strength and hardening for components fabricated of steel, aluminum alloy, asbestos cloth, copper alloy, elastomers and stainless steel. The applicant further stated that this program will utilize visual inspections performed during system walkdowns, which may be augmented by physical manipulation when appropriate, to detect the above mentioned aging.effects. The applicant clarified that this AMP is not credited for aging management for loss of material due to boric acid or for inspections of buried piping and aboveground steel tanks. The applicant further clarified that this AMP is not credited for aging management of the internal surfaces of components. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in GALL AMP XI.M36, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent, with an exception. Exception. The LRA states an exception to the GALL Report as follows: The NUREG-1801 aging management program XLM36, External Surfaces Monitoring program is based on system inspections and walkdowns. This program consists of periodic visual inspections of steel components such as piping, piping components, ducting, and other components within the scope of license renewal and subject to AMR in order to manage aging -effects. The program manages aging effects through visual inspection of external surfaces for evidence of material loss. Exceptions to NUREG-1801 are: 3-92

  • An increase to the scope of the materials inspected (i.e., aluminum alloy, asbestos cloth, copper alloy, elastomers, and stainless steel)." An increase to the scope of aging effects (i.e., hardening and loss of strength).

By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program" and "detection of aging effects" program elements.GALL AMP XI.M36 states that this program is limited to the detection of loss of material due to general, pitting and crevice corrosion for components fabricated of steel only. In RAI B.2.1.21-1,dated September 29, 2008, the staff requested that the applicant provide additional information to justify the basis for expanding the scope of materials and aging effects beyond steel components and loss of material due to general, pitting and crevice corrosion as recommended by GALL AMP XI.M36. The staff also requested that the applicant describe the details of the specific inspectiontechniques that will be used in detecting all the aging effects for all the materials within the scope of the program and to provide justification on how the program will be capable of managing loss of material due to cracking for asbestos.In part 1 of its response to the RAI dated October 20, 2008, the applicant stated that a visual inspection performed during system walkdowns will be capable of identifying loss of material for metallic components (aluminum alloy, copper alloy and stainless steel) other than steel. The applicant further stated that this visual inspection will monitor parameters such as corrosion, corrosion byproducts, coating degradation, discoloration on the surface, scale/deposits, and pits and surface discontinuities that are indicative of loss of material. The staff noted that metallic components, including copper alloy, aluminum alloy and stainless steel, would exhibit indications of loss of material on the surface similar to steel and a visual inspection will be capable of detecting age related degradation. The staff further noted that the these visual inspections will be performed by the applicant's staff that are qualified to perform the activities of the visual inspection in accordance with site controlled procedures and processes. Based on its review, the staff finds the applicant's response to Part 1 of RAI B.2.1.21-1 acceptable, and also finds the related portion of the exception acceptable because (1) the applicant will be performing visual inspections that are capable of detecting loss of material in metallic components as they display indications of degradation similar to steel, for which GALL AMP XI.M36 was intended and (2) these visual inspections will be performed by the applicant's staff that has been qualified in accordance with site controlled procedures and processes. In part 2 of its response to the RAI, the applicant stated that it will supplement the visual inspection of elastomeric components with a resiliency test that will be performed by compressingthe elastomeric components and then observing whether or not the material will return to its original shape. The applicant also stated the visual inspection performed during the system walkdown will look for indications of cracking and flaking of the elastomeric components. The staff noted that the resiliency test will supplement and aid the visual inspection in detecting age-related degradation because changes in material properties, such as hardening and loss of strength, can be detected during manipulation of elastomeric components by the relative inflexibility of the component, or by the failure of the component to return to its previous shape or configuration. Additionally, the applicant stated that corrective actions will be initiated if the inspection of these elastomeric components does not meet the acceptance criteria of this program, which is based on the component/material/environment combinations, design standards, industry codes and standards and engineering evaluation. 3-93* An increase to the scope of the materials inspected {Le., aluminum alloy, asbestos cloth, copper alloy, elastomers, and stainless steel}.

  • An increase to the scope of aging effects (Le., hardening and loss of strength).

By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program" and "detection of aging effects" program elements. GALL AMP XI,M36 states that this program is limited to the detection of loss of material due to general, pitting and crevice corrosion for components fabricated of steel only. In RAI B.2.1.21-1, dated September 29,2008, the staff requested that the applicant provide additional information to justify the basis for expanding the scope of materials and aging effects beyond steel components and loss of material due to general, pitting and crevice corrosion as recommended by GALL AMP XI.M36. The staff also requested that the applicant describe the details of the specific inspection techniques that will be used in detecting all the aging effects for all the materials within the scope of the program and to provide justification on how the program will be capable of managing loss of material due to cracking for asbestos. In part 1 of its response to the RAI dated October 20, 2008, the applicant stated that a visual inspection performed during system walkdowns will be capable of identifying loss of material for metallic components (aluminum alloy; copper alloy and stainless steel) other than steel. The applicant further stated that this visual inspection will monitor parameters such as corrosion, corrosion byproducts, coating degradation, discoloration on the surface, scale/deposits, and pits and surface discontinuities that are indicative of loss of material. The staff noted that metallic components, including copper alloy, aluminum alloy and stainless steel, would exhibit indications of loss of material on the surface similar to steel and a visual inspection will be capable of detecting age related degradation. The staff further noted that the these visual inspections will be performed by the applicant's staff that are qualified to perform the activities of the visual inspection in accordance with site controlled procedures and processes. Based on its review, the staff finds the applicant's response to Part 1 of RAI B.2.1.21-1 acceptable, and also finds the related portion of the exception acceptable because (1) the applicant will be performing visual inspections that are capable of detecting loss of material in metallic components as they display indications of degradation similar to steel, for which GALL AMP XI.M36 was intended and (2) these visual inspections will be performed by the applicant's staff that has been qualified in accordance with site controlled procedures and processes. In part 2 of its response to the RAI, the applicant stated that it will supplement the visual inspection of elastomeric components with a resiliency test that will be performed by compreSSing the elastomeric components and then observing whether or not the material will return to its original shape. The applicant also stated the visual inspection performed during the system walkdown will look for indications of cracking and flaking of the elastomeric components. The staff noted that the resiliency test will supplement and aid the visual inspection in detecting age-related degradation because changes in material properties, such as hardening and loss of strength, can be detected during manipulation of elastomeric components by the relative inflexibility of the component, or by the failure of the component to return to its previous shape or configuration. Additionally, the applicant stated that corrective actions will be initiated if the inspection of these elastomeric components does not meet the acceptance criteria of this program, which is based on the component/material/environment combinations, design standards, industry codes and standards and engineering evaluation. 3-93 Based on its review, the staff finds the applicant's response to part 2 of RAI B.1.2.21-1 acceptable, and also finds the related portion of the exception acceptable because (1) the applicant will supplement the visual inspection for elastomeric components with a resiliency test to compress the material and then observe whether or not the component will return to its original shape which is capable of detecting age-related degradation for elastomeric components as described above; and (2) the applicant will initiate corrective actions prior to these components not being capable of performing their intended function.In part 3 of its response to the RAI, the applicant stated that the program will manage loss of material due to cracking for asbestos cloth by periodic visual inspections performed during systemwalkdowns. The staff noted that the indications of loss of material for asbestos cloth include areas in which the material is cracked, missing or possibly flaking, so that a visual inspection would be capable of detecting age-related degradation associated with loss of material for asbestos cloth.Based on its review, the staff finds the applicant's response to part 3 of RAI B.1.2.21-1 acceptable, and also finds the related portion of the exception acceptable because the applicant will be monitoring asbestos cloth for loss of material due to cracking with a periodic visual inspection that will inspect for missing or cracked areas in the expansion joints and initiate corrective actions based on this program's acceptance criteria, which is consistent with the corresponding "acceptance criteria" program element defined in GALL AMP XI.M36.Based on its review, the staff finds the applicant's response to RAI B.2.1.21-1 acceptable and also finds all portions of the exception to the GALL Report acceptable. The staffs concerns described in RAI B.2.1.21-1 are resolved.Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.21 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.During a system walkdown in December 2004, the applicant stated that it discovered an unpainted/uncoated Circulating Water System valve which should be painted to prevent externalcorrosion. The staff noted that the applicant initiated corrective actions upon this discovery and the valve was painted to prevent external corrosion. The staff further noted that during a February 2006 walkdown, the applicant noted minor corrosion on the surface on the condenser shell of the Control Building Chiller. The applicant initiated corrective actions. The areas in which corrosion was discovered were cleaned and then repainted in order to prevent any further degradation. Based on this review, the staff finds (1) that the operating experience for this AMP demonstrates that the External Surfaces Monitoring program is achieving its objective of managing system components and (2) that the applicant is taking appropriate corrective actions through implementation of this program.The staff confirmed 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. 3-94 Based on its review, the staff finds the applicant's response to part 2 of RAI 6.1.2.21-1 acceptable, and also finds the related portion of the exception acceptable because (1) the applicant will supplement the visual inspection for elastomeric components with a resiliency test to compress the material and then observe whether or not the component will return to its original shape which is capable of detecting age-related degradation for elastomeric components as described above; and (2) the applicant will initiate corrective actions prior to these components not being capable of performing their intended function. In part 3 of its response to the RAI, the applicant stated that the program will manage loss of material due to cracking for asbestos cloth by periodic visual inspections performed during system walkdowns. The staff noted that the indications of loss of material for asbestos cloth include areas in which the material is cracked, missing or possibly flaking, so that a visual inspection would be capable of detecting age-related degradation associated with loss of material for asbestos cloth. Based on its review, the staff finds the applicant's response to part 3 of RAI B.1.2.21-1 acceptable, and also finds the related portion of the exception acceptable because the applicant will be monitoring asbestos cloth for loss of material due to cracking with a periodic visual inspection that will inspect for missing or cracked areas in the expansion joints and initiate corrective actions based on this program's acceptance criteria, which is consistent with the corresponding "acceptance criteria" program element defined in GALL AMP XI.M36. Based on its review, the staff finds the applicant's response to RAI B.2.1.21-1 acceptable and also finds all portions of the exception to the GALL Report acceptable. The staff's concerns described in RAI B.2.1.21-1 are resolved. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.21 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. During a system walkdown in December 2004, the applicant stated that it discovered an unpainted/uncoated Circulating Water System valve which should be painted to prevent external corrosion. The staff noted that the applicant initiated corrective actions upon this discovery and the valve was painted to prevent external corrosion. The staff further noted that during a February 2006 walkdown, the applicant noted minor corrosion on the surface on the condenser shell of the Control Building Chiller. The applicant initiated corrective actions. The areas in which corrosion was discovered were cleaned and then repainted in order to prevent any further degradation. Based on this review, the staff finds (1) that the operating experience for this AMP demonstrates that the External Surfaces Monitoring program is achieving its objective of managing system components and (2) that the applicant is taking appropriate corrective actions through implementation of this program. The staff confirmed the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1

o. The staff finds this program element acceptable.

3-94 UFSAR Supplement. LRA Section A.2.1.21 provides the applicant's UFSAR Supplement for the External Surfaces Monitoring Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staffs recommended UFSAR Supplement guidance found in the SRP-LR.In LRA Section A.5, Commitment No. 21, the applicant committed to implementing the program prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the External Surfaces Monitoring Program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its audit and review of the applicant's External Surfaces Monitoring Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exception and the associated justification and determined that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. The staff also reviewed the response to the RAI and finds it acceptable. The staff concludes that the applicant has demonstrated that effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.17 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Summary of Technical Information in the Application. LRA Section B.2.1.22 describes the new Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program as being consistent, with exceptions, with GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components." The applicant stated that this program will be credited for managing the following aging effects: cracking due to stress corrosion cracking, hardening and loss of strength due to elastomer degradation, loss of material due to general, pitting, crevice and microbiologically-influenced corrosion, cracking and fouling, and reduction of heat transfer due to fouling. The applicant further states that visual inspections of the internal surfaces will be performed to monitor for these aging effects and volumetric testing and physical manipulation of components may supplement the visual inspection, as needed.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exceptions to determine whether the AMP, with the exceptions, is adequate to manage the aging effects for which the LRA credits it.In comparing the elements in the applicant's program to those in GALL AMP XI.M38, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent, with an exception. The staff identified an issue with the "operating experience" program element and requested that the applicant provide additional information. The staff noted that the applicant did not mention that for elastomeric materials a physical manipulation of those components would supplement the visual inspection. In RAI B.2.1.22-3, dated September 29, 2008, the staff requested that the applicant provide additional information on whether the program description in the LRA should mention that for elastomeric components a physical manipulation will supplement the visual inspection. 3-95 UFSAR Supplement. LRA Section A.2.1.21 provides the applicant's UFSAR Supplement for the External Surfaces Monitoring Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staffs recommended UFSAR Supplement guidance found in the SRP-LR. In LRA Section A.5, Commitment No. 21, the applicant committed to implementing the program prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the External Surfaces Monitoring Program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's External Surfaces Monitoring Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exception and the associated justification and determined that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. The staff also reviewed the response to the RAI and finds it acceptable. The staff concludes that the applicant has demonstrated that effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.17 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Summary of Technical Information in the Application. LRA Section 8.2.1.22 describes the new Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program as being consistent, with exceptions, with GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components." The applicant stated that this program will be credited for managing the following aging effects: cracking due to stress corrosion cracking, hardening and loss of strength due to elastomer degradation, loss of material due to general, pitting, crevice and microbiologically-influenced corrosion, cracking and fouling, and reduction of heat transfer due to fouling. The applicant further states that visual inspections of the internal surfaces will be performed to monitor for these aging effects and volumetric testing and physical manipulation of components may supplement the visual inspection, as needed. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exceptions to determine whether the AMP, with the exceptions, is adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in GALL AMP XI.M38, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent, with an exception. The staff identified an issue with the "operating experience" program element and requested that the applicant provide additional information. The staff noted that the applicant did not mention that for elastomeric materials a physical manipulation of those components would supplement the visual inspection. In RAI 8.2.1.22-3, dated September 29, 2008, the staff requested that the applicant provide additional information on whether the program description in the LRA should mention that for elastomeric components a physical manipulation will supplement the visual inspection. 3-95 In its response to the RAI dated October 20, 2008, the applicant stated that a physical manipulation would supplement the periodic visual inspections as part of this AMP. The applicant amended LRA Sections A.2.1.22, B.2.1.22 (specifically the program description) and Commitment No. 22, to clearly identify that this AMP will be augmented by a physical manipulation of elastomeric components. The staff confirmed that the applicant amended the above mentioned LRA sections to include a clarification to augment the program with a physical manipulation. The staff noted that the applicant provided details of the physical manipulation in its response to RAI B.2.1.22-1, which is discussed later in this section.Based on its review, the staff finds the applicant's response to RAI B.2.1.22-3 acceptable because the applicant amended the LRA, specifically the UFSAR Supplement and Commitment No. 22, to indicate that a physical manipulation of elastomeric components.would supplement the periodic visual inspection performed as part of this AMP. The staffs concern described in RAI B.2.1.22-3 is resolved.Exceptions. The LRA states 4 exceptions to the GALL Report as follows: The NUREG-1801 aging management program XI.M38, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components consists of inspections of the internal surfaces of steel piping, piping components, ducting, and other components that are not covered by other aging management programs. These internal inspections are performed during the periodic system and component surveillances or during the performance of maintenance activities when the surfaces are made accessible for visual inspection. The program includes visual inspections to assure that existing environmental conditions are not causing material degradation that could result in a loss of component intended functions. Exceptions to NUREG-1801 are: " An increase of the component material types within the scope of this program (i.e., asbestos, copper alloy with 15% zinc or more, copper alloy with less than 15% zinc, neoprene, nickel alloy, rubber, stainless steel, and titanium alloy) (Exception No. 1).* An increase of the aging effects within the scope of this program (i.e., cracking, reduction of heat transfer, and hardening and loss of strength) (Exception No. 2).Volumetric testing will be used to detect SCC of stainless steel components (Exception No. 3).Physical manipulation may be used to detect hardening and loss of strength of elastomers both internally and externally (Exception No. 4).By letter dated October 30, 2008, the applicant stated that the exceptions apply to the program elements as follows:* Exception No. 1 applies to the "scope of program" program element." Exception No. 2 applies to the "scope of program," "parameters monitored/inspected," "monitoring and trending" and "acceptance criteria" program elements.3-96 In its response to the RAI dated October 20, 2008, the applicant stated that a physical manipulation would supplement the periodic visual inspections as part of this AMP. The applicant amended LRA Sections A.2.1.22, B.2.1.22 (specifically the program description) and Commitment No. 22, to clearly identify that this AMP will be augmented by a physical manipulation of elastomeric components. The staff confirmed that the applicant amended the above mentioned LRA sections to include a clarification to augment the program with a physical manipulation. The staff noted that the applicant provided details of the physical manipulation in its response to RAI B.2.1.22-1, which is discussed later in this section. Based on its review, the staff finds the applicant's response to RAI B.2.1.22-3 acceptable because the applicant amended the LRA, specifically the UFSAR Supplement and Commitment No. 22, to indicate that a physical manipulation of elastomeric components.would supplement the periodic visual inspection performed as part of this AMP. The staffs concern described in RAI B.2.1.22-3 is resolved. Exceptions. The LRA states 4 exceptions to the GALL Report as follows: The NUREG-1801 aging management program XI.M38, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components consists of inspections of the internal surfaces of steel piping, piping components, ducting, and other components that are not covered by other aging management programs. These internal inspections are performed during the periodic system and component surveillances or during the performance of maintenance activities when the surfaces are made accessible for visual inspection. The program includes visual inspections to assure that existing environmental conditions are not causing material degradation that could result in a loss of component intended functions. Exceptions to NUREG-1801 are:

  • An increase of the component material types within the scope of this program (Le., asbestos, copper alloy with 15% zinc or more, copper alloy with less than 15% zinc, neoprene, nickel alloy, rubber, stainless steel, and titanium alloy) (Exception No.1).
  • An increase of the aging effects within the scope of this program (Le., cracking, . reduction of heat transfer, and hardening and loss of strength) (Exception No.2).
  • Volumetric testing will be used to detect see of stainless steel components (Exception No.3).
  • Physical manipulation may be used to detect hardening and loss of strength of elastomers both internally and externally (Exception No.4). By letter dated October 30, 2008, the applicant stated that the exceptions apply to the program elements as follows:
  • Exception No. 1 applies to the "scope of program" program element.
  • Exception No.2 applies to the "scope of program," "parameters monitored/inspected," "monitoring and trending" and "acceptance criteria" program elements.

3-96

  • Exception No. 3 applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects" and "monitoring and trending" program elements." Exception No. 4 applies to the "scope of program," "parametersmonitored/inspected," "detection of aging effects" and "monitoring and trending" program elements.The staff noted that the applicant's exceptions are interconnected, such that the expansion inaging effects (i.e. cracking, reduction in heat transfer and hardening and loss of strength) are only applicable to certain materials that have been added to the scope of this AMP. The staff further noted that additional inspection techniques are only applicable to certain material and aging effect combinations.

The staff has evaluated these exceptions such that the appropriate material, aging effect and inspection technique combination were taken into consideration; GALL AMP XI.M38 states that this program is limited to the detection of visible evidence of corrosion to indicate possible loss of material for components fabricated of steel only with the use of a visual inspection. The staff determined that additional information was required from the applicant to provide justification for expanding of the scope of materials that this AMP will manage and to provide justification for expanding the scope of aging effects that this AMP will detect toinclude cracking, reduction of heat transfer, loss of strength and hardening. In RAI B.2.1.22-1, dated September 29, 2008, the staff requested that the applicant provide additional information to justify the basis for expanding the scope of materials and aging effects, as described above, beyond steel components and loss of material as recommended by GALL AMP XI.M38. The staffalso asked the applicant to describe the details of the specific inspection techniques that will be used in detecting all the aging effects for all the materials within the scope of this AMP and to justify the inspection techniques' ability to detect these aging effects during the period of extended operation. In part 1 of its response to the RAI dated October 20, 2008, the applicant stated that a visual inspection that is performed during system and component surveillance and maintenance activities will be capable of identifying loss of material for metallic components (copper alloy, nickel alloy, stainless steel and titanium) other than steel. The applicant further stated that the visual inspection performed during inspections will monitor parameters such as corrosion, corrosion byproducts, coating degradation, discoloration on the surface, scale/deposits, pits and surface discontinuities. The staff noted that metallic components, including copper alloy, nickel alloy, stainless steel and titanium, would exhibit indications of loss of material on the surface similar to steel and a visual inspection will be capable of detecting age related degradation. Thestaff also noted that the these visual inspections will be performed by the applicant's staff that are qualified to perform the activities of the visual inspection in accordance with site controlled procedures and processes. Regarding minimizing the potential for reduction of heat transfer capability, the applicant stated that the external surfaces of cooling coils will be inspected and cleaned for fouling at the same time that the internal surfaces of these components will be visually inspected as part of this program. The staff further noted that a visual inspection of the cooling coil surface will be capable of detecting any fouling (build up from whatever source) on the internal and external surface. The staff noted in the GALL AMP XI.M38 the "monitoring and trending" element states that results of the periodic inspections are monitored for indications of corrosion and fouling; and the "acceptance criteria" element states that indications of fouling that would impact component intended function are reported and will require further evaluation. 3-97* Exception No.3 applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects" and "monitoring .and trending" program elements.

  • Exception No.4 'applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects" and "monitoring and trending" program elements.

The staff noted that the applicant's exceptions are interconnected, such that the expansion in aging effects (Le. cracking, reduction in heat transfer and hardening and loss of strength) are only applicable to certain materials that have been added to the scope of this AMP. The staff further noted that additional inspection techniques are only applicable to certain material and aging effect combinations. The staff has evaluated these exceptions such that the appropriate material, aging effect and inspection technique combination were taken into consideration, GALL AMP XI.M38 states that this program is limited to the detection of visible evidence of corrosion to indiGate possible loss of material for components fabricated of steel only with the use of a visual inspection. The staff determined that additional information was required from the applicant to provide justification for expanding of the scope of materials that this AMP will manage and to provide justification for expanding the scope of aging effects that this AMP will detect to include cracking, reduction of heat transfer, loss of strength and hardening. In RAI B.2.1.22-1, dated September 29, 2008, the staff requested that the applicant provide additional information to justify the basis for expanding the scope of materials and aging effects, as described above, beyond steel components and loss of material as recommended by GALL AMP XI.M38. The staff also asked the applicant to describe the details of the specific inspection techniques that will be used in detecting all the aging effects for all the materials within the scope of this AMP and to justify the inspection techniques' ability to detect these aging effects during the period of extended operation. In part 1 of its response to the RAI dated October 20, 2008, the applicant stated that a visual inspection that is performed during system and component surveillance and maintenance activities will be capable of identifying loss of material for metallic components (copper alloy, nickel alloy, stainless steel and titanium) other than steel. The applicant further stated that the visual inspection performed during inspections will monitor parameters such as corrosion, corrosion byproducts, coating degradation, discoloration on the surface, scale/deposits. pits and surface discontinuities. The staff noted that metallic components, including copper alloy, nickel alloy, stainless steel and titanium, would exhibit indications of loss of material on the surface similar to steel and a visual inspection will be capable of detecting age related degradation. The staff also noted that the these visual inspections will be performed by the applicant's staff that are qualified to perform the activities of the visual inspection in accordance with site controlled procedures and processes. Regarding minimizing the potential for reduction of heat transfer capability, the applicant stated that the external surfaces of cooling coils will be inspected and cleaned for fouling at the same time that the internal surfaces of these components will be visually inspected as part of this program. The staff further noted that a visual inspection of the cooling coil surface will be capable of detecting any fouling (build up from whatever source) on the internal and external surface. The staff noted in the GALL AMP XI.M38 the "monitoring and trending" element states that results of the periodic inspections are monitored for indications of corrosion and fouling; and the "acceptance criteria" element states that indications of fouling that would impact component intended function are reported and will require further evaluation. 3-97 Based on its review, the staff finds part I of the applicant's response to RAI 8.2.1.22-1 acceptable, and also finds the related exception acceptable because (1) the applicant will be performing visual inspections that are capable of detecting loss of material in metallic components as they display indications of corrosion similar to steel, for which GALL AMP XI.M38 was intended, (2) these visual inspections will be performed by the applicant's staff that has been qualified in accordance with site controlled procedures and processes, (3) this program requires visual inspections to detect fouling, which may lead to the aging effect of reduction in heat transfer, which is consistent with the recommendations GALL AMP XI.M38.In part 2 of its response to the RAI, the applicant stated that it will supplement the visual inspection of elastomeric components with a resiliency test that will be performed by compressing the elastomeric components and then observing whether or not the material will return to its original shape. The applicant also stated the visual inspection performed during the system and component surveillance and maintenance activities will look for indications of cracking and flaking of the elastomeric components. The staff noted that the resiliency test will supplement and aid the visual inspection in detecting age-related degradation because changes in material properties, such as hardening and loss of strength, can be detected during manipulation of elastomeric components by the relative inflexibility of the component, or by the failure of the component to return to its previous shape or configuration. The staff further noted that the applicant will initiate corrective actions if the inspection of these elastomer components does not meet the acceptance criteria of this program. The acceptance criteria are established in the maintenance and surveillance procedures or other established plant procedures so that indications of degradation that would impact component intended function arereported and will require further evaluation. Based on its review, the staff finds part 2 of the applicant's response to RAI B.2.1.22-1 acceptable and also finds the related portion of the exception acceptable because (1) the applicant will supplement the visual inspection for elastomeric components with a resiliency test to compress the material and then observe whether or not the component will return to its original shape, which is capable of detecting age-related degradation for elastomeric components as described above, and (2) the applicant will initiate corrective actions prior to these components not being capable of performing their intended function.In part 3 of its response to the RAI, the applicant stated that this AMP will manage loss of material due to cracking for asbestos cloth by periodic visual inspections performed during system and component surveillance and maintenance activities. The staff noted that the indications of loss of material for asbestos cloth include areas in which the material is cracked, missing or possibly flaking, so that a visual inspection would be capable of detecting age-related degradation associated with loss of material for asbestos cloth.Based on its review, the staff finds part 3 of the applicant's response to RAI B.2.1.22-1 acceptable, and also finds the related portion of the exception acceptable because the applicant will be monitoring asbestos cloth for loss of material due to cracking with a periodic visual inspection that will inspect for missing or cracked areas in the expansion joints and initiate corrective actions based on this program's acceptance criteria, which is consistent with the corresponding "acceptance criteria" program element defined in GALL AMP XI.M38.In part 4 of its response to the RAI, the applicant stated that the detection of any cracking from the ultrasonic testing that is performed on stainless steel components susceptible to stress corrosion cracking will be entered into the corrective actions process and will then be evaluated. 3-98 Based on its review, the staff finds part 1 of the applicant's response to RAI B.2.1.22-1 acceptable, and also finds the related exception acceptable because (1) the applicant will be performing visual inspections that are capable of detecting loss of material in metallic components as they display indications of corrosion similar to steel, for which GALL AMP XI.M38 was intended, (2) these visual inspections will be performed by the applicant's staff that has been qualified in accordance with site controlled procedures and processes, (3) this program requires visual inspections to detect fouling, which may lead to the aging effect of reduction in heat transfer, which is consistent with the recommendations GALL AMP XI.M38. In part 2 of its response to the RAI, the applicant stated that it will supplement the visual inspection of elastomeric components with a resiliency test that will be performed by compressing the elastomeric components and then observing whether or not the material will return to its original shape. The applicant also stated the visual inspection performed during the system and component surveillance and maintenance activities will look for indications of cracking and flaking of the elastomeric components. The staff noted that the resiliency test will supplement and aid the visual inspection in detecting age-related degradation because changes in material properties, such as hardening and loss of strength, can be detected during manipulation of elastomeric components by the relative inflexibility of the component, or by the failure of the component to return to its previous shape or configuration. The staff further noted that the applicant will initiate corrective actions if the inspection of these elastomer components does not meet the acceptance criteria of this program. The acceptance criteria are established in the maintenance and surveillance procedures or other established plant procedures so that indications of degradation that would impact component intended function are reported and will require further evaluation. Based on its review, the staff finds part 2 of the applicant's response to RAI B.2.1.22-1 acceptable and also finds the related portion of the exception acceptable because (1) the applicant will supplement the visual inspection for elastomeric components with a resiliency test to compress the material and then observe whether or not the component will return to its original shape, which is capable of detecting age-related degradation for elastomeric components as described above, and (2) the applicant will initiate corrective actions prior to these components not being capable of performing their intended function. In part 3 of its response to the RAI, the applicant stated that this AMP will manage loss of material due to cracking for asbestos cloth by periodic visual inspections performed during system and component surveillance and maintenance activities. The staff noted that the indications of loss of material for asbestos cloth include areas in which the material is cracked, missing or possibly flaking, so that a visual inspection would be capable of detecting age-related degradation associated with loss of material for asbestos cloth. Based on its review, the staff finds part 3 of the applicant's response to RAI B.2.1.22-1 acceptable, and also finds the related portion of the exception acceptable because the applicant will be monitoring asbestos cloth for loss of material due to cracking with a periodic visual inspection that will inspect for missing or cracked areas in the expansion joints and initiate corrective actions based on this program's acceptance criteria, which is consistent with the corresponding "acceptance criteria" program element defined in GALL AMP XI.M38. In part 4 of its response to the RAI, the applicant stated that the detection of any cracking from the ultrasonic testing that is performed on stainless steel components susceptible to stress corrosion cracking will be entered into the corrective actions process and will then be evaluated. 3-98 The staff further noted that the applicant's evaluation for the test or inspection results from the ultrasonic testing are performed when the acceptance criteria, defined as the detection of any cracking, is not met and a condition report is created to document the issue in accordance with plant procedures that meet the requirements of 10 CFR Part 50, Appendix B. Based on the staffs review of GALL AMP XI.M32 "One-Time Inspection," the staff noted that this GALL AMP recommends that the use of a volumetric inspection technique (either radiographic testing [RT] or ultrasonic testing [UT]) is adequate for detection of cracking due to stress corrosion cracking. The staff further noted the applicant's use of ultrasonic testing to detect cracking due to stress corrosion cracking is consistent with the recommendations given by the GALL Report.Based on its review, the staff finds part 4 of the applicant's response to RAI B.2.1.22-1 acceptable, and also finds the related portion of the exception to be acceptable because (1) the applicant will initiate corrective actions upon the detection of any indication of cracking when inspecting components with the use of an ultrasonic inspection technique and (2) the applicant's use of an ultrasonic test to detect cracking due to stress corrosion cracking is consistent with the recommendations of the GALL AMP XI.M32.Based on its review, the staff finds the applicant's response to RAI B.2.1.22-1 acceptable and also finds all portions of the exception to the GALL Report acceptable, as discussed above. The staff's concerns described in RAI B.2.1.22-1 are resolved.Operatinq Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.22 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The staff noted that the applicant found deposits on the fans and coolers of the Reactor Building Fans and Coolers during the refueling outage in 2003. The staff further noted that the boron deposits were cleaned and the reactor coolant leak that caused the deposits was corrected. The staff determined that additional information was needed regarding the applicant's subsequent inspections of the Reactor Building Fans and Coolers. In RAI B.2.1.22-2, dated September 29, 2008 the staff requested that the applicant provide additional information to describe the results of the internal inspections subsequent to the discovery of the boron deposits identified during the 2003 refueling outage. The staff also asked the applicant to clarify whether the existing procedures have been capable of managing age-related degradation in this system that would impact the components intended function.In its response to the RAI dated October 20, 2008, the applicant stated that the inspections and cleaning of the Reactor Building air handling units are routinely performed during refueling outages, which occur at a 2-year frequency. The staff noted that the applicant performed external and internal evaluations and non-destructive examinations (NDE), whose results indicated that the corrosion that had occurred was within acceptable limits. The applicant stated that since the discovery of the boron deposits during the 2003 refueling outage, there have been two subsequent inspections which have identified negligible deposits of boron that have not resulted in significant degradation of the cooling coils or the air-handling units. The staff noted that the applicant is continuing to monitor and trend the inspection results to make certain that the loss of intended functions for these components will not occur.3-99* or,; The staff further noted that the applicant's evaluation for the test or inspection results from the ultrasonic testing are performed when the acceptance criteria, defined as the detection of any cracking, is not met and a condition report is created to document the issue in accordance with plant procedures that meet the requirements of 10 CFR Part 50, Appendix B. Based on the staff's review of GALL AMP XI.M32 "One-Time Inspection," the staff noted that this GALL AMP recommends that the use of a volumetric inspection technique (either radiographic testing [RT] or ultrasonic testing [UT]) is adequate for detection of cracking due to stress corrosion cracking. The staff further noted the applicant's use of ultrasonic testing to detect cracking due to stress corrosion cracking is consistent with the recommendations given by the GALL Report. Based on its review, the staff finds part 4 of the applicant's response to RAI B.2.1.22-1 acceptable, and also finds the related portion of the exception to be acceptable because (1) the applicant will initiate corrective actions upon the detection of any indication of cracking when inspecting components with the use of an ultrasonic inspection technique and (2) the applicant's use of an ultrasonic test to detect cracking due to stress corrosion cracking is consistent with the recommendations of the GALL AMP XI.M32. Based on its review, the staff finds the applicant's response to RAI B.2.1.22-1 acceptable and also finds all portions ofthe exception to the GALL Report acceptable, as discussed above. The staff's concerns described in RAI. B.2.1.22-1 are resolved. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.22 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The staff noted that the applicant found deposits on the fans and coolers of the Reactor Building Fans and Coolers during the refueling outage in 2003. The staff further noted that the boron deposits were cleaned and the reactor coolant leak that caused the deposits was corrected. The staff determined that additional information was needed regarding the applicant's subsequent inspections of the Reactor Building Fans and Coolers. In RAI B.2.1.22-2, dated September 29, 2008 the staff requested that the applicant provide additional information to describe the results of the internal inspections subsequent to the discovery of the boron deposits identified during the 2003 refueling outage. The staff also asked the applicant to clarify whether the existing procedures have been capable of managing age-related degradation in this system that would impact the components intended function. In its response to the RAI dated October 20, 2008, the applicant stated that the inspections and cleaning of the Reactor Building air handling units are routinely performed during refueling outages, which occur at a 2-year frequency. The staff noted that the applicant performed external and internal evaluations and non-destructive examinations (NDE), whose results indicated that the corrosion that had occurred was within acceptable limits. The applicant stated that since the discovery of the boron deposits during the 2003 refueling outage, there have been two subsequent inspections which have identified negligible deposits of boron that have not resulted in significant degradation of the cooling coils or the air-handling units. The staff noted that the applicant is continuing to monitor and trend the inspection results to make certain that the loss of intended functions for these components will not occur. 3-99 Based on its review, the staff finds the applicant's response to RAI B.2.1.22-2 acceptable because (1) the applicant has routinely (2-year frequency) inspected these components and based on the applicant's evaluations and NDE results, degradation beyond acceptable limits has not occurred and (2) the applicant will continue to monitor and trend inspection results to ensure that corrective actions will be initiated prior to the loss of intended functions for these components. The staffs concern described in RAI B.2.1.22-2 is resolved.Based on its review, the staff finds (1) that the operating experience for this AMP demonstratesthat the AMP is achieving its objective of managing system components and(2) that the applicant is taking appropriate corrective actions through implementation of this program.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. LRA Section A.2.1.22 provides the applicant's UFSAR Supplement for the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staffs recommended UFSAR Supplement guidance found in the SRP-LR.The staff noted that LRA Section A.2.1.22 and LRA Section A.5, Commitment No. 22 did not state that for elastomeric materials a physical manipulation of those components would supplement the visual inspection. In RAI B.2.1.22-3, dated September 29, 2008, the staff requested that the applicant clarify whether or not Commitment No. 22 and LRA Section A.2.1.22 should mention that for elastomeric components a physical manipulation will supplement the visual inspection. In its response to the RAI dated October 20, 2008, the applicant amended LRA Section A.2.1.22, B.2.1.22 and Commitment No. 22, to clearly identify that this AMP will be augmented by a physical manipulation for elastomeric components. Based on its review, the staff finds the applicant's response to RAI B.2.1.22-3 acceptable because the applicant's amendment identifies that physical manipulation will be performed for elastomers. The staffs concern described in RAI B.2.1.22-3 is resolved.In LRA Section A.5, Commitment No. 22, the applicant committed to augment this AMP with a physical manipulation for elastomeric components for detection of hardening and loss of strength.The staff finds that the applicant has provided an adequate summary description of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program as required by 10 CFR 54.21(d).Conclusion. On the basis of its audit and review of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exception and the associated justification and determined that the AMP, with the exception, is adequate to manage the aging effects for which it is credited. The staff also reviewed the RAI responses and finds them acceptable. The staff concludes that the applicant has demonstrated that effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as 3-100 Based on its review, the staff finds the applicant's response to RAI B.2.1.22-2 acceptable because (1) the applicant has routinely (2-year frequency) inspected these components and based on the applicant's evaluations and NDE results, degradation beyond acceptable limits has not occurred and (2) the applicant will continue to monitor and trend inspection results to ensure that corrective actions will be initiated prior to the loss of intended functions for these components. The staff's concern described in RAI B.2.1.22-2 is resolved. Based on its review, the staff finds (1) that the operating experience for this AMP demonstrates that the AMP is achieving its objective of managing system components and-(2) that the applicant is taking appropriate corrective actions through implementation of this program. The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1 O. The staff finds this program element acceptable. UFSAR Supplement. LRA Section A.2.1.22 provides the applicant's UFSAR Supplement for the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR. The staff noted that LRA Section A.2.1.22 and LRA Section A.5, Commitment No. 22 did not state that for elastomeric materials a physical manipulation of those components would supplement the visual inspection. In RAI B.2.1.22-3, dated September 29, 2008, the staff requested that the applicant clarify whether or not Commitment No. 22 and LRA Section A.2.1.22 should mention that for elastomeric components a physical manipulation will supplement the visual inspection. In its response to the RAI dated October 20,2008, the applicant amended LRA Section A.2.1.22, B.2.1.22 and Commitment No. 22, to clearly identify that this AMP will be augmented by a physical manipulation for elastomeric components. Based on its review, the staff finds the applicant's response to RAI B.2.1.22-3 acceptable because the applicant's amendment identifies that physical manipulation will be performed for elastomers. The staff's concern described in RAI B.2.1.22-3 is resolved. In LRA Section A.5, Commitment No. 22, the applicant committed to augment this AMP with a physical manipulation for elastomeric components for detection of hardening and loss of strength. The staff finds that the applicant has provided an adequate summary description of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exception and the associated justification and determined that the AMP, with the exception, is adequate to manage the aging effects for which it is credited. The staff also reviewed the RAI responses and finds them acceptable. The staff concludes that the applicant has demonstrated that effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as 3-100 required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.18 Lubricating Oil Analysis Summary of Technical Information in the Application. LRA Section B.2.1.23 describes the applicant's existing Lubricating Oil Analysis Program as being consistent, with an exception, to GALL AMP XI.M39, "Lubricating Oil System." The applicant stated that the program provides oil condition monitoring activities to manage the loss of material and the reduction of heat transfer in piping, piping components, piping elements, heat exchangers, and tanks within the scope of license renewal exposed to a lubricating oil environment. Sampling and condition monitoring activities identify specific wear products, contamination and the physical properties of lubricating oil within operating machinery to ensure that intended functions are maintained. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it.In comparing the elements in the applicant's program to those in GALL AMP XI.M39, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent, with an exception. Exception. The LRA states an exception to the GALL Report as follows: NUREG-1 801 recommends that flash point be determined for lubricating oil. Flash point will not be measured for all lubricating oil in service. The determination of flash point in lubricating oil is used to indicate the presence of highly volatile or flammable materials in a relatively nonvolatile or nonflammable material, such as found with fuel contamination in lubricating oil. The TMI-1 oil analysis guidelines only include the measurement of flashpoint for diesel engine lubricating oil where there is the potential for the contaminationof lubricating oil with fuel. Flash point is not measured for other lubricating oils where there is no potential for the contamination of lubricating oil with fuel. For all lubricating oils, flash point is used as a quality control measurement when receiving new oil. Flash point is not a primary measurement to determine the presence of water or contaminants in lubricating oil, which are the environmental parameters necessary for the loss of material and reduction ofheat transfer aging effects.By letter dated October 30, 2008, the applicant stated that this exception applies to the"parameters monitored/inspected" program element.The staff confirmed that the Lubricating Oil Analysis Program provides for monitoring of the flashpoint for lubricating oil in diesel engine applications where the potential for dilution of lubricating oil is possible. The staff noted that monitoring the flash point of lubricating oil is a method that willdetermine the level of dilution of lubricating oil with fuel oil. As the flash point decreases, the dilution increases. The staff noted that it is not necessary to monitor flash point for non-diesel applications because the potential for lubricating oil dilution with fuel oil and the concomitant reduction of flash point is minimal.Based on its review, the staff finds this exception to the GALL Report acceptable. 3-101 required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.18 Lubricating Oil Analysis Summary of Technical Information in the Application. LRA Section B.2.1.23 describes the applicant's existing Lubricating Oil Analysis Program as being consistent, with an exception, to GALL AMP XI.M39, "Lubricating Oil System." The applicant stated that the program provides oil condition monitoring activities to manage the loss of material and the reduction of heat transfer in piping, piping components, piping elements, heat exchangers, and tanks within the scope of license renewal exposed to a lubricating oil environment. Sampling and condition monitoring activities identify specific wear products, contamination and the physical properties of lubricating oil within operating machinery to ensure that intended functions are maintained. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in GALL AMP XI.M39, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent, with an exception. Exception. The LRA states an exception to the GALL Report as follows: NUREG-1801 recommends that flash point be determined for lubricating oil. Flash point will not be measured for all lubricating oil in service. The determination of flash point in lubricating oil is used to indicate the presence of highly volatile or flammable materials in a relatively nonvolatile or nonflammable material, such as found with fuel contamination in lubricating oil. The TMI-1 oil analysis guidelines only include the measurement of flash point for diesel engine lubricating oil where there is the potential for the contamination,of lubricating oil with fuel. Flash point is not measured for other lubricating oils where there is no potential for the contamination of lubricating oil with fuel. For all lubricating oils, flash point is used as a quality control measurement when receiving new o,il. Flash point is not a primary measurement to determine the presence of water or contaminants in lubricating oil, which are the environmental parameters necessary for the loss of material and reduction of heat transfer aging effects. . By letter dated October 30, 2008, the applicant stated that this exception applies to the "parameters monitored/inspected" program element. The staff confirmed that the Lubricating Oil Analysis Program provides for monitoring of the flash point for lubricating oil in diesel engine applications where the potential for dilution of lubricating oil is possible. The staff noted that monitoring the flash point of lubricating oil is a method that will determine the level of dilution of lubricating oil with fuel oil. As the flash point decreases, the dilution increases. The staff noted that it is not necessary to monitor flash point for non-diesel applications because the potential for lubricating oil dilution with fuel oil and the concomitant reduction of flash point is minimal. . Based on its review, the staff finds this exception to the GALL Report acceptable. 3-101 Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.23 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant stated that demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that aging effects/mechanisms are being adequately managed consistent with the CLB for the period of extended operation. The staff noted that during routine review of oil sample data, the applicant discovered increased particle content in the main turbine oil reservoir and the Feedwater pump/turbine reservoir. The corrective action process indicated no bearing degradation. The source of the particulate was the bowser filter which was subsequently replaced. The staff noted that the documentation provided by the applicant during the onsite review supported the applicant's statements regarding operating experience and confirmed that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff confirmed the "operating experience" program element satisfies the criterion defined in the GALL Report and SRP-LR Section A. 1.2.3.10. The staff finds this program element acceptable. UFSAR Supplement. LRA Section A.2.1.23 provides the applicant's UFSAR Supplement for the Lubricating Oil Analysis Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staffs recommended UFSAR Supplement guidance found in the SRP-LR.In LRA Section A.5, Commitment No. 23, the applicant committed to the continued implementation of the existing Lubricating Oil Analysis Program on an ongoing basis.The staff finds that the applicant has provided an adequate summary description of the Lubricating Oil Analysis Program as required by 10 CFR 54.21(d).Conclusion. On the basis of its audit and review of the applicant's Lubricating Oil Analysis Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and its justification and finds that the AMP, with the exception, is adequate to manage the aging effects for which it is credited. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.19 ASME Section XI, Subsection IWE Summary of Technical Information in the Application. LRA Section B.2.1.24 describes the existing ASME Section Xl, Subsection IWE Program as being consistent, with an exception with GALL AMP XI.S1 "ASME Section Xl, Subsection IWE." 3-102 Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.23 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The applicant stated that demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that aging effects/mechanisms are being adequately managed consistent with the CLB for the period of extended operation. The staff noted that during routine review of oil sample data, the applicant discovered increased particle content in the main turbine oil reservoir and the Feedwater pump/turbine reservoir. The corrective action process indicated no bearing degradation. The source of the particulate was the bowser filter which was subsequently replaced. The staff noted that the documentation provided by the applicant during the onsite review supported the applicant's statements regarding operating experience and confirmed that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The staff confirmed the "operating experience" program element satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.1 O. The staff finds this program element acceptable. UFSAR Supplement. LRA Section A.2.1.23 provides the applicant's UFSAR Supplement for the Lubricating Oil Analysis Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR. In LRA Section A.5, Commitment No. 23, the applicant committed to the continued implementation of the existing Lubricating Oil Analysis Program on an ongoing basis. The staff finds that the applicant has provided an adequate summary description of the Lubricating Oil Analysis Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Lubricating Oil Analysis Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and its justification and finds that the AMP, with the exception, is adequate to manage the aging effects for which it is credited. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.19 ASME Section XI, Subsection IWE Summary of Technical Information in the Application. LRA Section B.2.1.24 describes the existing ASME Section XI, Subsection IWE Program as being consistent, with an exception with GALL AMP XI.S1 "ASME Section XI, Subsection IWE." 3-102 The applicant stated that the program provides for the inspection of the reactor building liner plate, including its integral attachments, penetration sleeves, pressure retaining bolting, personnel airlock and equipment hatch, seals, gaskets, and moisture barrier, and other pressure retaining components. The applicant state that section 10 CFR 50.55a specifies the use of the examination requirements in the ASME Code, Section Xl, Subsection IWE, for steel liners of concrete -containments and other containment components and that it has implemented the ASME Section XI, Subsection IWE, 1992 Edition including 1992 Addenda for current 10-year inspection interval, approved per 10 CFR 50.55a, for managing the aging effects of loss of material (general, pitting, and crevice corrosion), loss of pressure retaining bolting preload, cracking due to cyclic loading, loss of sealing, leakage through containment/deterioration of seals, gaskets, and moisture barriers (caulking, flashing, and other sealants). The applicant further stated that it will adopt new ASME Code editions and addenda consistent with the provisions of 10 CFR 50.55a for the next 10-year inspection interval starting in 2011.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it.In comparing the elements in the applicant's program to those in GALL AMP XI.S1, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent, with an exception. The staff identified an issue with the "operating experience" program element and requested that the application provide additional information. Exception. The LRA states an exception to the GALL Report as follows: NUREG-1801 evaluation is based on ASME Section Xl, 2001 Edition including 2002 and 2003 Addenda. The current TMI-1 ASME Section Xl, Subsection IWE program plan for the First 10-Year Inspection Interval effective from September 9, 2001 through April 19, 2011, approved per 10 CFR 50.55a, is based on ASME Section Xl, 1992 Edition including 1992 addenda. The next 10-Year Inspection Interval for TMI-1 will incorporate the requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a 12 months before the start of the inspection interval.The staff noted that the ASME code edition referenced by the applicant was previously approved under 10 CFR 50.55a for the ten-year interval. The use of the 1992 edition through the 1992 Addenda of the ASME code is consistent with the provisions in the 10 CFR 50.55a to use the code in effect 12 months prior to the start of the inspection interval. The staff has concluded that the stated exception should not be identified as such because no exception is needed for requirements found in the 2001 edition, but not in the 1992 edition of the code. In RAI B.2.1.24-1,dated October 7, 2008, the staff requested that the applicant provide additional information to indicate the applicant's agreement or provide justification if the applicant disagreed with the staff's determination. In its response to the RAI dated October 30, 2008, the applicant agreed with the staff that a formal exception to the ASME code version listed in the GALL Report is not required since the code edition used for the program, had been previously approved under 10 CFR 50.55a for this ten-year interval. The applicant also amended LRA Section B.2.1.24 to delete the previously stated exception to the GALL Report. The applicant further made corresponding changes of related items in LRA Tables 3.2.1, 3.5.1 and Table 3.5.2.3-103 The applicant stated that the program provides for the inspection of the reactor building liner plate, including its integral attachments, penetration sleeves, pressure retaining bolting, personnel airlock and equipment hatch, seals, gaskets, and moisture barrier, and other pressure retaining components. The applicant state that section 10 CFR 50.55a specifies the use of the examination requirements in the ASME Code, Section XI, Subsection IWE, for steel liners of concrete -containments and other containment components and that it has implemented the ASME Section XI, Subsection IWE, 1992 Edition including 1992 Addenda for current 1 O-year inspection interval, approved per 10 CFR 50.55a, for managing the aging effects of loss of material (general, pitting, and crevice corrosion), loss of pressure retaining bolting preload, cracking due to cyclic loading, loss of sealing, leakage through containment/deterioration of seals, gaskets, and moisture barriers (caulking, flashing, and other sealants). The applicant further stated that it will adopt new ASME Code editions and addenda consistent with the provisions of 10 CFR 50.55a for the next 1 O-year inspection interval starting in 2011. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of conSistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in GALL AMP XI.S1, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent, with an exception. The staff identified an issue with the "operating experience" program element and requested that the application provide additional information. Exception. The LRA states an exception to the GALL Report as follows: NUREG-1801 evaluation is based on ASME Section XI, 2001 Edition including 2002 and 2003 Addenda. The current TMI-1 ASME Section XI, Subsection IWE program plan for the First 10-Year Inspection Interval effective from September 9, 2001 through April 19, 2011, approved per 10 CFR 50.55a, is based on ASME Section XI, 1992 Edition including 1992 addenda. The next 10-Year Inspection Interval for TMI-1 will incorporate the requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a 12 months before the start of the inspection interval. The staff noted that the ASME code edition referenced by the applicant was previously approved under 10 CFR 50.55a for the ten-year interval. The use of the 1992 edition through the 1992 Addenda of the ASME code is consistent with the provisions in the 10 CFR 50.55a to use the code in effect 12 months prior to the start of the inspection interval. The staff has concluded that the stated exception should not be identified as such because no exception is needed for requirements found in the 2001 edition, but not in the 1992 edition of the code. In RAI B.2.1.24-1, dated October 7,2008, the staff requested that the applicant provide additional information to indicate the applicant's agreement or provide justification if the applicant disagreed with the staff's determination. In its response to the RAI dated October 30, 2008, the applicant agreed with the staff that a formal exception to the ASME code version listed in the GALL Report is not required since the code edition used for the program, had been previously approved under 10 CFR 50.55a for this ten-year interval. The applicant also amended LRA Section B.2.1.24 to delete the previously stated exception to the GALL Report. The applicant further made corresponding changes of related items in LRA Tables 3.2.1, 3.5.1 and Table 3.5.2. 3-103 Based on its review, the staff finds the applicant's response to RAI B.2.1.24-1 acceptable because the applicant agreed with the staffs determination that differences in ASME Code editions need not be identified as exceptions to the GALL Report, and because the applicant amended the LRA to delete the exception to the program. The staffs concern described in RAI B.2.1.24-1 is resolved.The staff finds that the program includes all ASME Code, Section Xl inspection requirements for the steel liner of the concrete containment (Class CC).The staff finds the applicant's ASME Section Xl, Subsection IWE program acceptable because it conforms to the recommendations of GALL AMP XI.S1, "ASME Section Xl, Subsection IWE." Operatinq Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.24 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The staff noted that the liner thickness corrosion rate was noticeable from operating experience provided, especially at locations adjacent to the moisture barrier at elevation 281' and 279'-6". To ensure the essential leak-tight condition of the containment for the period of extended operation, the staff identified an issue concerning the restoration of degraded plate areas where additional information was needed to complete its review.In the LRA, the applicant committed to replacing the existing steam generators with new OTSGs prior to entering the period of extended operation. The applicant stated that the repair/replacement of the reactor building liner plate, removed for access purposes, will be performed in accordance with ASME Section XI, Subsection IWE. The applicant indicated that the liner will be restored (weld repair) to full design thickness at all locations identified as less than90% before entering the period of extended operation. In RAI B.2.1.24-2, dated October 7, 2008, the staff requested that the applicant provide additional information to confirm the repairs and provide the proposed schedule for completion. In its response to the RAI dated October 30, 2008, the applicant stated that prior to the period of extended operation, the reactor building liner will be restored to its nominal plate thickness by weld repair for the previously identified corroded areas where the thickness of the base metal is reduced by more than 10% of the nominal plate thickness. The applicant added this information to LRA Table A.5, as Commitment No. 42.Based on its review, the staff finds the applicant's response to RAI B.2.1.24-2 acceptable because the applicant provided a Commitment for the completion of restoration of degraded plate areas of the reactor building liner plate. The staffs concern described in RAI B.2.1.24-2 is resolved, The staff confirmed the "operating experience" program element satisfies the criterion defined in the GALL Report and SRP-LR Section A. 1.2.3.10. The staff finds this program element acceptable. 3-104 Based on its review, the staff finds the applicant's response to RAI B.2.1.24-1 acceptable because the applicant agreed with the staffs determination that differences in ASME Code editions need not be identified as exceptions to the GALL Report, and because the applicant amended the LRA to delete the exception to the program. The staffs concern described in RAI B.2.1.24-1 is resolved. The staff finds that the program includes all ASME Code, Section XI inspection requirements for the steel liner of the concrete containment (Class CC). The staff finds the applicant's ASME Section XI, Subsection IWE program acceptable because it conforms to the recommendations of GALL AMP XI.S1, "ASME Section XI, Subsection IWE." Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.24 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The staff noted that the liner thickness corrosion rate was noticeable from operating experience provided, especially at locations adjacent to the moisture barrier at elevation 281' and 279'-6". To ensure the essential leak-tight condition of the containment for the period of extended operation, the staff identified an issue concerning the restoration of degraded plate areas where additional information was needed to complete its review. In the LRA, the applicant committed to replacing the existing steam generators with new OTSGs prior to entering the period of extended operation. The applicant stated that the repair/replacement of the reactor building liner plate, removed for access purposes, will be performed in accordance with ASME Section XI, Subsection IWE. The applicant indicated that the liner will be restored (weld repair) to full design thickness at all locations identified as less than 90% before entering the period of extended operation. In RAI B.2.1.24-2, dated October 7,2008, the staff requested that the applicant provide additional information to confirm the repairs and provide the proposed schedule for completion. In its response to the RAI dated October 30, 2008, the applicant stated that prior to the period of extended operation, the reactor building liner will be restored to its nominal plate thickness by weld repair for the previously identified corroded areas where the thickness of the base metal is reduced by more than 10% of the nominal plate thickness. The applicant added this information to LRA Table A.5, as Commitment No. 42. Based on its review, the staff finds the applicant's response to RAI B.2.1.24-2 acceptable because the applicant provided a Commitment for the completion of restoration of degraded plate areas of the reactor building liner plate. The staffs concern described in RAI B.2.1.24-2 is resolved. The staff confirmed the "operating experience" program element satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.1 O. The staff finds this program element acceptable. 3-104 UFSAR Supplement. LRA Section A.2.1.24 provides the applicant's UFSAR Supplement for the ASME Section Xl, Subsection IWE Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staffs recommended UFSAR Supplement guidance found in the SRP-LR.In LRA Section A.5, Commitment No. 24, the applicant credited the existing program on an ongoing basis.In LRA Section A.5, Commitment No. 42, the applicant committed to complete restoration of degraded plate areas of the reactor building liner plate operation prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the ASME Section XI, Subsection IWE Program as required by 10 CFR 54.21(d).Conclusion. On the basis of its audit and review of the applicant's ASME Section Xl, Subsection IWE Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. In addition, the staff reviewed the exception and its justification and finds that the exception did not need to be identified as such, and that the AMP is adequate to manage the aging effects for which the LRA credits it. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.20 ASME Section XI, Subsection IWF Summary of Technical Information in the Application. LRA Section B.2.1.26 describes the existing ASME Section Xl, Subsection IWF program as being consistent, with an exception, with GALL AMP XI.S3 "ASME Section XI, Subsection IWF." The applicant stated that the program is implemented through plant procedures, which provide for periodic visual inservice inspection of class 1, 2, and 3 component supports for loss of mechanical function and material and that section 50.55a of 10 CFR specifies the use of the examination requirements in the ASME Code, Section XI, Subsection IWF, for ASME Class 1, 2, 3, and MC piping and components and their associated supports. The applicant also stated that it has implemented ASME Section XI, Subsection IWF, 1995 Edition with the 1996 Addenda, for managing the aging effects of loss of mechanical function, loss of material, lock-up due wear, and loss of bolting function (which includes loss of material and loss of preload by inspecting for missing, detached, or loosened bolts). The applicant further stated that it will adopt new ASME Code editions and addenda consistent with the provisions of 10 CFR 50.55a for the next 10-year inspection interval starting in 2011.Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it.In comparing the elements in the applicant's program to those in GALL AMP XI.S3, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent, with an exception. 3-105 UFSAR Supplement. LRA Section A.2.1.24 provides the applicant's UFSAR Supplement for the ASME Section XI, Subsection IWE Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR. In LRA Section A.5, Commitment No. 24, the applicant credited the existing program on an ongoing basis. In LRA Section A.5, Commitment No. 42, the applicant committed to complete restoration of degraded plate areas of the reactor building liner plate operation prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the ASME Section XI, Subsection IWE Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's ASME Section XI, Subsection IWE Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report, are consistent. In addition, the staff reviewed the exception and its justification and finds that the exception did not need to be identified as such, and that the AMP is adequate to manage the aging effects for which the LRA credits it. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplementfor this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.20 ASME Section XI, Subsection IWF Summary of Technical Information in the Application. LRA Section B.2.1.26 describes the existing ASME Section XI, Subsection IWF program as being consistent, with an exception, with GALL AMP XI.S3 "ASME Section XI, Subsection IWF." The applicant stated that the program is implemented through plant procedures, which provide for periodic visual inservice inspection of class 1, 2, and 3 component supports for loss of mechanical function and material and that section 50.55a of 10 CFR specifies the use of the examination requirements in the ASME Code, Section XI, Subsection IWF, for ASME Class 1, 2, 3, and MC piping and components and their associated supports. The applicant also s*tated that it has implemented ASME Section XI, Subsection IWF, 1995 Edition with the 1996 Addenda, for managing the aging effects of loss of mechanical function, loss of material, lock-up due wear, and loss of bolting function (which includes loss of material and loss of preload by inspecting for missing, detached, or loosened bolts). The applicant further stated that it will adopt new ASME Code editions and addenda consistent with the provisions of 10 CFR 50.55a for the next 10-year inspection interval starting in 2011. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in GALL AMP XI.S3, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent, with an exception. 3-105 The staff finds that the applicant's ASME Section Xl, Subsection IWF program includes all ASME Code, Section X1 inspection requirements for Class 1, 2, 3, and MC piping and components and their associated supports.Exception. The LRA states an exception to the GALL Report as follows: NUREG-1801 evaluation covers the 2001 edition including the 2002 and 2003 Addenda, as approved in 10 CFR 50.55a. The current TMI-1 ISI Program Plan for the Third Ten-Year Inspection Interval effective from April 20, 2001 through April 19, 2011, approved per 10 CFR 50.55a, is based on the 1995 ASME Section Xl B&PV Code, including 1996 addenda.The next 120-month inspection interval for TMI-1 will incorporate the requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a twelve months before the start of the inspection interval.The staff noted that the ASME code edition referenced by the applicant was previously approved under 10 CFR 50.55a for the ten-year interval. The use of the 1995 edition through the 1996 Addenda of the ASME code is consistent with the provisions in the 10 CFR 50.55a to use the Code in effect 12 months prior to the start of the inspection interval. The staff has concluded thatthe stated exception should not be identified as such because no exception is needed for requirements found in the 2001 edition, but not in the 1992 edition of the code. In RAI B.2.1.26-1, dated October 7, 2008, the staff requested that the applicant provide additional information to indicate agreement or to provide justification if the applicant disagreed with the staffs determination. In its response to the RAI dated October 30, 2008, the applicant agreed with the staff that a formal exception to the ASME code version listed in the GALL Report, Revision 1 is not required since the code edition used for the program, ASME 1995 Edition including the 1996 addenda, had been previously approved under 10 CFR 50.55a for this ten-year interval. The applicant also amended LRA Section B.2.1.26 to delete the previously stated exception to the GALL Report. The applicant further made corresponding changes of related items in LRA Tables 3.5.1 and Table 3.5.2.Based on its review, the staff finds the applicant's response to RAI B.2.1.26-1 acceptable because the applicant agreed with the staffs determination that differences in the specified ASME Code Section Xl editions need not be identified as exceptions to the GALL Report, and because the applicant amended the LRA by deleting the previously stated exception to the ASME Section Xl, Subsection IWF Program. The staff's concern described in RAI B.2.1.26-1 is resolved.Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.26 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant explained that the operating experience of the ISI Program -IWF activities shows no adverse trend of program performance. The applicant stated that visual examinations conducted in 1999 identified that three class 2 supports were found unacceptable and requiredrepair and that the unacceptable condition was related to loose or missing bolts or nuts. The applicant stated that as a result of the unacceptable conditions, the scope of inspection was 3-106 The staff finds that the applicant's ASME Section XI, Subsection IWF program includes all ASME Code, Section XI inspection requirements for Class .1, 2, 3, and MC piping and components and their associated supports. Exception. The LRA states an exception to the GALL Report as follows: NUREG-1801 evaluation covers the 2001 edition including the 2002 and 2003 Addenda, as approved in 10 CFR 50.55a. The current TMI-1 lSI Program Plan for the Third Ten-Year Inspection Interval effective from April 20, 2001 through April 19, 2011, approved per 10 CFR 50.55a, is based on the 1995 ASME Section XI B&PV Code, including 1996 addenda. The next 120-month inspection interval for TMI-1 will incorporate the requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a twelve months before the start of the inspection interval. The staff noted that the ASME code edition referenced by the applicant was previously approved under 10 CFR 50.55a for the ten-year interval. The use of the 1995 edition through the 1996 Addenda of the ASME code is consistent with the provisions in the 10 CFR 50.55a to use the Code in effect 12 months prior to the start of the inspection interval. The staff has concluded that the stated exception should not be identified as such because no exception is needed for requirements found in the 2001 edition, but not in the 1992 edition of the code. In RAI B.2.1.26-1, dated October 7,2008, the staff requested that the applicant provide additional information to indicate agreement or to provide justification if the applicant disagreed with the staffs determination. In its response to the RAI dated October 30,2008, the applicant agreed with the staff that a formal exception to the ASME code version listed in the GALL Report, Revision 1 is not required since the code edition used for the program, ASME 1995 Edition including the 1996 addenda, had been previously approved under 10 CFR 50.55a for this ten-year interval. The applicant also amended LRA Section B.2.1.26 to delete the previously stated exception to the GALL Report. The' applicant further made corresponding changes of related items in LRA Tables 3.5.1 and Table 3.5.2. Based on its review, the staff finds the applicant's response to RAI B.2.1.26-1 acceptable because the applicant agreed with the staffs determination that differences in the specified ASME Code Section XI editions need not be identified as exceptions to the GALL Report, and because the applicant amended the LRA by deleting the previously stated exception to the ASME Section XI, Subsection IWF Program. The staff's concern described in RAI B.2.1.26-1 is resolved. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.26 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The applicant explained that the operating experience of the 151 Program -IWF activities shows no adverse trend of program performance. The applicant stated that visual examinations conducted in 1999 identified that three class 2 supports were found unacceptable and required repair and that the unacceptable condition was related to loose or missing bolts or nuts. The* applicant stated that as a result of the unacceptable conditions, the scope of inspection was 3-106 expanded three times to include additional supports in order to determine the extent of such conditions. The applicant also stated that visual examinations conducted in 2001, 2003, and 2005 identified non-recordable indications that consisted of minor surface rust, loose bolts or nuts, and out of tolerance hot or cold settings for piping and component supports and that the loose bolts and nuts were tightened and the out of tolerance settings were restored to meet design requirements. The applicant further stated that the surface rust was evaluated and determined not to impact the structural integrity of the supports.The staff finds assurance that the program is capturing degradation and correcting it in accordance with ASME Section Xl and concludes that administrative controls are effective in detecting age-related degradation and initiating corrective action. The staff confirmed 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. LRA Section A.2.1.26 provides the UFSAR Supplement for the ASME Section XI, Subsection IWF Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staffs recommended UFSAR Supplement guidance found in the SRP-LR.In LRA Section A.5, Commitment No. 26, the applicant credited the existing program on an ongoing basis.The staff finds that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d).Conclusion. On the basis of its audit and review of the applicant's ASME Section Xl, Subsection IWF Program the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exception anddetermined that it did not need to be identified as such, and that the AMP is adequate to manage the aging effects for which the LRA credits it. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concluded that the applicant has provided an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.21 Structures Monitoring Program Summary of Technical Information in the Application. LRA Section B.2.1.28 describes the existing Structures Monitoring Program as being consistent, with enhancements, to GALL AMP XI.S6,"Structures Monitoring Program." The LRA states that the program will manage aging effects such that loss of material, cracking, change of material properties, and loss of form are detected by visual inspection with a frequency of every 5 years maximum, with provisions for more frequent inspections to ensure that there is no loss of structure or structural component intended function(s). The applicant also stated that the program consists of the Masonry Wall Program and RG 1.127, "Water Control Structures Inspection." 3-107 expanded three times to include additional supports in order to determine the extent of such conditions. The applicant also stated that visual examinations conducted in 2001, 2003, and 2005 identified non-recordable indications that consisted of minor surface rust, loose bolts or nuts, and out of tolerance hot or cold settings for piping and component supports and that the loose bolts . and nuts were tightened and the out of tolerance settings were restored to meet design requirements. The applicant further stated that the surface rust was evaluated and determined not to impact the structural integrity of the supports. The staff finds assurance that the program is capturing degradation and correcting it in accordance with ASME Section XI and concludes that administrative controls are effective in detecting age-related degradation and initiating corrective action. The staff confirmed the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1

o. The staff finds this program element acceptable.

UFSAR Supplement. LRA Section A.2.1.26 provides the UFSAR Supplement for the ASME Section XI, Subsection IWF Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staffs recommended UFSAR Supplement guidance found in the SRP-LR. In LRA Section A.5, Commitment No. 26, the applicant credited the existing program on an ongoing basis. . The staff finds that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's ASME Section XI, Subsection IWF Program the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exception and determined that it did not need to be identified as such, and that the AMP is adequate to manage the aging effects for which the LRA credits it. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concluded that the applicant has provided an adequate summary description of the program, as required by 10 CFR 54.21(d). ' 3.0.3.2.21 Structures Monitoring Program Summary of Technical Information in the Application. LRA Section B.2.1.28 describes the existing Structures Monitoring Program as being consistent, with enhancements, to GALL AMP XI.S6, "Structures Monitoring Program." The LRA states that the program will manage aging effects such that loss of material, cracking, change of material properties, and loss of form are detected by visual inspection with a frequency of every 5 years maximum, with provisions for more frequent inspections to ensure that there is no loss of structure or structural component intended function(s). The applicant also stated that the program consists of the Masonry Wall Program and RG 1.127, "Water Control Structures Inspection." 3-107 Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. The staff reviewed the enhancements (Commitment No. 28) to determine whether the AMP, with the enhancements, is adequate to manage the aging effects for which it is credited in the LRA.During its audit, the staff audited the applicant's on-site documentation supporting the applicant's conclusion that the program elements are consistent with the elements in the GALL Report. The staff interviewed the applicant's technical staff and reviewed the documents related to the Structures Monitoring Program, including the license renewal program evaluation report in which the applicant claimed the program elements are consistent with GALL AMP XI.S6.Enhancements. LRA Section B.2.1.28 states an enhancement to: , Include service building, UPS diesel building, mechanical draft cooling tower structures, miscellaneous yard structures (foundation for condensate storage tank, borated water storage tank, diesel fuel storage tank, altitude tank, duct banks, and manholes). By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program" program element.The staff reviewed the applicant's Structures Monitoring Program, and its AERMs under the"scope of program" program element of the Structures Monitoring Program. The staff noted that the Structures Monitoring Program satisfies the monitoring requirements for plant structures that are within the scope of the NRC Maintenance Rule (10 CFR 50.65). TMI-1 structures and components that are within the scope of license renewal monitored by the Structures Monitoring Program include the following: -Service Building-UPS Diesel Building-Intake Canal-Mechanical Draft Cooling Tower Structures -Miscellaneous Yard Structures (Foundation for condensate storage tank, borated water storage tank, diesel fuel storage tank, altitude tank, duct banks, and manholes); -Inspection of submerged reinforced concrete for Intake Screen house and Pumphouse, Circulating Water Pump House, Mechanical Draft Cooling Tower Structures, Natural Draft Tower Basins. In the letter dated September 19, 2008, the applicant added the Circulating Water Tunnel -Penetration Seals-Cabinets, and Enclosures for Electrical Equipment and Components -HVAC duct supports for loss of material 3-108 Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. The staff reviewed the enhancements (Commitment No. 28) to determine whether the AMP, with the enhancements, is adequate to manage the aging effects for which it is credited in the LRA. During its audit, the staff audited the applicant's on-site documentation supporting the applicant's conclusion that the program elements are consistent with the elements in the GALL Report. The staff interviewed the applicant's technical staff and reviewed the documents related to the Structures Monitoring Program, including the license renewal program evaluation report in which the applicant claimed the program elements are with GALL AMP XI.S6. Enhancements. LRA Section B.2.1.28 states an enhancement to:

  • Include servic;:e building, UPS diesel building, mechanical draft cooling tower structures, miscellaneous yard structures (foundation for condensate storage tank, borated water storage tank, diesel fuel storage tank, altitude tank, duct banks, and manholes).

By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program" program element. The staff reviewed the applicant's Structures Monitoring Program, and its AERMs under the "scope of program" program element of the Structures Monitoring Program. The staff noted that the Structures Monitoring Program satisfies the monitoring requirements for plant structures that are within the scope of the NRC Maintenance Rule (10 CFR 50.65). TMI-1 structures and components that are within the scope of license renewal monitored by the Structures Monitoring Program include the following: -Service Building -UPS Diesel Building -Intake Canal -Mechanical Draft Cooling Tower Structures -Miscellaneous Yard Structures (Foundation for condensate storage tank, borated water storage tank, diesel fuel storage tank, altitude tank, duct banks, and manholes); -Inspection of submerged reinforced concrete for Intake Screen house and Pumphouse, Circulating Water Pump House, Mechanical Draft Cooling Tower Structures, Natural Draft Tower Basins. In the letter dated September 19, 2008, the applicant added the Circulating Water Tunnel -Penetration Seals -Cabinets, and Enclosures for Electrical Equipment and Components -HVAC duct supports for loss of material 3-108 The staff found this enhancement acceptable because when the enhancement is implemented, TMI-1 AMP B.2.1.28, "Structures Monitoring Program," will be consistent with GALL AMP XI.S6 and provide additional assurance that the effects of aging will be adequately managed.LRA Section B.2.1.28 includes additional enhancements to: (1) Monitor penetration seals that perform flood barrier, shelter, protection, and pressure boundary intended functions. (2) Monitor the intake canal for loss of material and loss of form.(3) Monitor electrical panels, junction boxes, instrument panels, and conduits for loss of material due to corrosion. (4) Monitor ground water chemistry by periodically sampling, testing, and analysis of ground water to confirm that the environment remains non-aggressive for buried reinforced concrete.(5) Monitor reinforced concrete submerged in raw water associated with intake screen and pumphouse, circulating water pump house, mechanical draft cooling tower structures, natural draft cooling tower basins.(6) Monitor vibration isolators, associated with component supports other than those covered by ASME Xl, Subsection IWF, for reduction or loss of isolation function. (7) Parameters monitored will be enhanced to include plausible aging mechanisms. (8) Monitor concrete structures for a reduction in anchor capacity due to local concrete degradation. This will be accomplished by visual inspection of concrete surfaces around anchors for cracking, and spalling.By letter dated October 30, 2008, the applicant stated that these enhancements apply to the program elements as follows: (1) Applies to the "scope of program," and "parameters monitored/inspected," program elements.(2) Applies to the "scope of program," "parameters monitored/inspected," and "acceptance criteria" program elements.(3) Applies to the "scope of program" program element.(4) Applies to the "detection of aging effects" program element.(5) Applies to the "scope of program," and "detection of aging effects" program elements.(6) Applies to the "parameters monitored/inspected" program element.(7) Applies to the "parameters monitored/inspected" program element.3-109 The staff found this enhancement acceptable because when the enhancement is implemented, TMI-1 AMP B.2.1.28, "Structures Monitoring Program," will be consistent with GALL AMP XI.S6 and provide additional assurance that the effects of aging will be adequately managed. LRASection B.2.1.28 includes additional enhancements to: (1) Monitor penetration seals that perform flood barrier, shelter, protection, and pressure boundary intended functions. (2) Monitor the intake canal for loss of material and loss of form. (3) Monitor electrical panels, junction boxes, instrument panels, and conduits for loss of material due to corrosion. (4) Monitor ground water chemistry by periodically sampling, testing, and analysis of ground water to confirm that the environment remains non-aggressive for buried reinforced concrete. (5) Monitor reinforced concrete submerged in raw water associated with intake screen and pumphouse, circulating water pump house, mechanical draft cooling tower structures, natural draft cooling tower basins. (6) Monitor vibration isolators, associated with component supports other than those covered by ASME XI, Subsection IWF, for reduction or loss of isolation function. (7) Parameters monitored will be enhanced to include plausible aging mechanisms. (8) Monitor concrete structures for a reduction in anchor capacity due to local concrete degradation. This will be accomplished by visual inspection of concrete surfaces around anchors for cracking, and spalling. By letter dated October 30, 2008, the applicant stated that these enhancements apply to the program elements as follows: (1) Applies to the "scope of program," and "parameters monitored/inspected," program elements. (2) Applies to the "scope of program," "parameters monitored/inspected," and "acceptance criteria" program elements. C (3) Applies to the "scope of program" program element. (4) Applies to the "detection of aging effects" program element. (5) Applies to the "scope of program," and "detection of aging effects" program elements. (6) Applies to the "parameters monitored/inspected" program element. (7) Applies to the "parameters monitored/inspected" program element. 3-109 (8) Applies to the "parameters monitored/inspected" program element.The staff reviewed the applicant's Structures Monitoring Program, and its AERMs under the"parameters monitored or inspected" program element of the Structures Monitoring Program. The staff noted that the TMI-1 Structures Monitoring Program will be enhanced to include the following: -Include reinforced concrete plausible aging mechanisms. -Concrete structures will also be observed for a reduction in anchor capacity due to local concrete degradation. This will be accomplished by visual inspection of concrete surfaces around anchors for cracking, and spalling.-Clarify that inspection be performed for loss of material due to corrosion (general, crevice, pitting) for steel components, such as embedment, panels and enclosures, doors, siding, metal deck, structural bolting, and anchors.-Require inspection of penetration seals and structural seals, for degradations that will lead to a loss of seal by visual inspection of the seal for cracking, chipping, and hardening. -Require monitoring of vibration isolators, associated with component supports other than those covered by ASME XI, Subsection IWF, for reduction or loss of isolation function by inspecting the isolators for cracking and hardening. -Intake Canal will be monitored for loss of material, loss of form/erosion, settlement, sedimentation, waves and currents.-Periodic sampling, testing and analysis of ground water to confirm that the environment remains non-aggressive for buried reinforced concrete.The staff also found that the program will be enhanced to require inspection of submerged structures in raw water on a frequency of 5 years. Inspection will be performed by a diver or by using remote video or other special safety equipment. During its audit and review, in RAI B.2.1.28-1, dated October 7, 2008, the staff asked the applicant to provide the time frame of the "periodic" sampling and the results for the last twogroundwater samplings. In its responses dated October 30, 2008, (ML083080376) the applicant stated that the groundwater sampling for pH, chloride, and sulfate concentrations will be performed every 5 years during the period of extended operation. The last two groundwater samplings include one sample taken in 2007 and three taken in 2005. The results are as follows: Sample Date 6/19/2007 7/7/2005 Location MS-22 Well "A" Well "B" Well "C" pH 7.4 7.8 7.8 7.7 Chloride (ppm) 58 57.3 42.4 65.5 Sulfates (ppm) 27 44.2 53.3 48.0 The staff found the above values meet the GALL Report limits (pH > 5.5; chloride < 500ppm;sulfate < 1500ppm) for non-aggressive ground water. The staffs concerns described in RAI B.2.1-3-110 (B) Applies to the "parameters monitored/inspected" program element. The staff reviewed the applicant's Structures Monitoring Program, and its AERMs under the "parameters monitored or inspected" program element of the Structures Monitoring Program. The staff noted that the TMI-1 Structures Monitoring Program will be enhanced to include the following: Include reinforced concrete plausible aging mechanisms. Concrete structures will also be observed for a reduction in anchor capacity due to local concrete degradation. This will be accomplished by visual inspection of concrete surfaces around anchors for cracking, and spalling. Clarify that inspection be performed for loss of material due to corrosion (general, crevice, pitting) for steel components, such as embedment, panels and enclosures, doors, siding, metal deck, structural bolting, and anchors. Require inspection of penetration seals and structural seals, for degradations that will lead to a loss of seal by visual inspection of the seal for cracking, chipping, and hardening. Require monitoring of vibration isolators, associated with component supports other than those covered by ASME XI, Subsection IWF, for reduction or loss of isolation function by inspecting the isolators for cracking and hardening. Intake Canal will be monitored for loss of material, loss of form/erosion, settlement, sedimentation, waves and currents. Periodic sampling, testing and analysis of ground water to confirm that the environment remains non-aggressive for buried reinforced concrete. The staff also found. that the program will be enhanced to require inspection of submerged structures in raw water on a frequency of 5 years. Inspection will be performed by a diver or by using remote video or other special safety equipment. During its audit and review, in RAI B.2.1.2B-1, qated October 7, 200B, the staff asked the applicant to provide the time frame of the "periodic" sampling and the results for the last two groundwater samplings. In its responses dated October 30, 200B, (MLOB30B0376) the applicant stated that the groundwater sampling for pH, chloride, and sulfate concentrations will be performed every 5 years during the period of extended operation. The last two groundwater samplings include one sample taken in 2007 and three taken in 2005. The results are as follows: Sample Date 6/19/2007 7/7/2005 Location MS-22 Well "A" Well "B"* Well"C" pH 7.4 7.B 7.B 7.7 Chloride (ppm) 5B 57.3 42.4 65.5 Sulfates (ppm) 27 44.2 53.3 4B.0 The staff found the above values meet the GALL Report limits (pH> 5.5; chloride < 500ppm; sulfate < 1500ppm) for non-aggressive ground water. The staff's concerns described in RAI B.2.1-3-110 28-1 are resolved. The staff also finds this enhancement acceptable because when the enhancement is implemented, TMI-1 AMP B.2.1.28, "Structures Monitoring Program," will be consistent with GALL AMP XI.S6 and provide additional assurance that the effects of aging will beadequately managed. LRA Section B.2.1.28 also includes an enhancement to: 0 Revise acceptance criteria to provide details specified in ACI 349.3R-96. By letter dated October 30, 2008, the applicant stated that this enhancement applies to the"acceptance criteria" program element.The staff reviewed the applicant's Structures Monitoring Program, and its AERMs under the"acceptance criteria" program element of the Structures Monitoring Program. The staff noted that the TMI-1 Structures Monitoring Program will be enhanced to include the following:

  • Implementing procedures will be enhanced to detailed acceptance criteria specified in ACI 349.3R-96, Chapter 5." Implementing procedures will be enhanced to require that loss of material and loss of form for the Intake Canal be evaluated to ensure the required volume of emergency cooling water is in accordance with UFSAR Section 2.6.

The staff finds this enhancement acceptable because acceptance criteria are typically established such that corrective actions are initiated prior to loss of function and when the enhancement is implemented, TMI-1 AMP B.2.1.28, "Structures Monitoring Program," will be consistent with GALL AMP XI.S6 and provide additional assurance that the effects of aging will be adequately managed.Operatingq Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.28 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant stated that that silt accumulation was observed at the discharge of the 48-inch diameter emergency river water dump line and the silt covered approximately half the diameter of the pipe outlet, a condition also observed in 1999, during the baseline inspections. The applicant further stated that an engineering evaluation concluded that the discharge line remained capable of performing its intended function.In RAI B.2.1.28-2, dated October 7, 2008, the staff requested that the applicant provide additional information to explain the conclusion reached in the engineering evaluation concerning silt in the emergency river water dump line.In its response to the RAI dated October 30, 2008, the applicant stated that it assumed the 48" diameter pipe was reduced to a 24" diameter for the length containing silt. The applicant further 3-111 28-1 are resolved. The staff also finds this enhancement acceptable because when the enhancement is implemented, TMI-1 AMP 8.2.1.28, "Structures Monitoring Program," will be consistent with GALL AMP XI.S6 and provide additional assurance that the effects of aging will be adequately managed. LRA Section 8.2.1.28 also includes an enhancement to:

  • Revise acceptance criteria to provide details specified in ACI 349.3R-96.

8y letter dated October 30, 2008, the applicant stated that this enhancement applies to the "acceptance criteria" program element. The staff reviewed the applicant's Structures Monitoring Program, and its AERMs under the "acceptance criteria" program element of the Structures Monitoring Program. The staff noted that the TMI-1 Structures Monitoring Program will be enhanced to include the following:

  • Implementing procedures will be enhanced to detailed acceptance criteria specified in ACI 349.3R-96, Chapter 5.
  • Implementing procedures will be enhanced to require that loss of material and loss of form for the Intake Canal be evaluated to ensure the required volume of emergency cooling water is in accordance with UFSAR Section 2.6. The staff finds this enhancement acceptable because acceptance criteria are typically established such that corrective actions are initiated prior to loss of function and when the enhancement is implemented, TMI-1 AMP 8.2.1.28, "Structures Monitoring Program," will be consistent with GALL AMP XI.S6 and provide additional assurance that the effects of aging will be adequately managed. Operating Experience.

The staff reviewed the operating experience provided in LRA Section 8.2.1.28 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The applicant stated that that silt accumulation was observed at the discharge of the 48-inch diameter emergency river water dump line and the silt covered approximately half the diameter of the pipe outlet, a condition also observed in 1999, during the baseline inspections. The applicant further stated that an engineering evaluation concluded that the discharge line remained capable of performing its intended function. In RAI 8.2.1.28-2, dated October 7, 2008, the staff requested that the applicant provide additional information to explain the conclusion reached in the engineering evaluation concerning silt in the emergency river water dump line. In its response to the RAI dated October 30, 2008, the applicant stated that it assumed the 48" diameter pipe was reduced to a 24" diameter for the length containing silt. The applicant further 3-111 stated that the resulting head loss due to the restricted flow was determined not to affect the required flow rate and, therefore, the intended function for the pipe remained unaffected. The applicant also stated that the analysis is conservative in that the 24" diameter assumed for the pipe length containing silt, results in / of the area provided by the 48" diameter pipe being restricted, vs. having 11/2 of the 48" pipe diameter actually restricted by silt.Based on its review, the staff finds the applicant's response to RAI B.2.1.28-2 acceptable because the applicant demonstrated that only % of the area provided by the 48" pipe is required to conduct the flow. The staff's concern described in RAI B.2.1.28-2 is resolved.The staff conducted a field walk-down with the applicant's technical staff to verify some existing conditions of the intake canal including the flood dike, riprap, crack on the masonry wall's mortar joints at the 355 feet elevation of the turbine building's airshaft, mechanical draft cooling tower, and the Unit -2 fuel handling building. Overall, the staff found them in good condition and performing well. All of the observations are minor and acceptable in accordance with the applicant's inspection procedures which are within the guidance of ACI 201.1R (Guide for Making a Condition Survey of Concrete in Service) and ACI 349-3R (Evaluation of Existing Nuclear Safety-Related Concrete Structures) as recommended in the GALL Report.The staff finds that the applicant's Structures Monitoring Program, with the corrective actions discussed in the LRA, has been effective in identifying, monitoring, and correcting the effects ofaging on structures monitoring and the existing program operating experience revealed no degradation not bounded by industry experience. 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. LRA Section A.2.1.28 provides the UFSAR Supplement for the Structures Monitoring Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR.In LRA Section A.5, Commitment No. 28, the applicant committed to implement the enhancements prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the program as required by 10 CFR 54.21(d).Conclusion. On the basis of its audit and review of the applicant's Structures Monitoring Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the enhancements and confirmed that their implementation through Commitment No. 28 prior to the period of extended operation would make the existing AMP consistent with the GALL AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program, as required by 10 CFR 54.21(d).3-112 stated that the resulting head loss due to the restricted flow was determined not to affect the required flow rate and, therefore, the intended function for the pipe remained unaffected. The applicant also stated that the analysis is conservative in that the 24" diameter assumed for the pipe length containing silt, results in of the area provided by the 48" diameter pipe being restricted, vs. having Y2 of the 48" pipe diameter actually restricted by silt. Based on its review, the staff finds the applicant's response to RAI B.2.1.28-2 acceptable because the applicant demonstrated that only of the area provided by the 48" pipe is required to conduct the flow. The staff's concern described in RAI B.2.1.28-2 is resolved. The staff conducted a field walk-down with the applicant's technical staff to verify some existing conditions of the intake canal including the flood dike, riprap, crack on the masonry wall's mortar joints at the 355 feet elevation of the turbine building's airshaft, mechanical draft cooling tower, and the Unit -2 fuel handling building. Overall, the staff found them in good condition and performing well. All of the observations are minor and acceptable in accordance with the applicant's inspection procedures which are within the guidance of ACI 201.1 R (Guide for Making a Condition Survey of Concrete in Service) and ACI 349-3R (Evaluation of Existing Nuclear Safety-Related Concrete Structures) as recommended in the GALL Report. The staff finds that the applicant's Structures Monitoring Program, with the corrective actions discussed in the LRA, has been effective in identifying, monitoring, and correcting the effects of aging on structures monitoring and the existing program operating experience revealed no degradation not bounded by industry experience. The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1 O. The staff finds this program element acceptable. UFSAR Supplement. LRA Section A.2.1.28 provides the UFSAR Supplement for the Structures Monitoring Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR. In LRA Section A.5, Commitment No. 28, the applicant committed to implement the enhancements prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the program as required by. 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Structures Monitoring Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the enhancements and confirmed that their implementation through Commitment No. 28 prior to the period of extended operation would make the existing AMP consistent with the GALL AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program, as required by 10 CFR 54.21(d). 3-112 3.0.3.2.22 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Summary of Technical Information in the Application. LRA Section B.2.1.31 describes the existing Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program as being consistent, with an enhancement, with GALL AMP XI.E2, "Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits." The applicant stated that this program will provide reasonable assurance that the intended functions of electrical cables that are not subject to the environmental qualification requirements of 10 CFR 50.49 and are used in instrumentation circuits with sensitive, high voltage, low-level signals exposed to adverse localized environments caused by heat, radiation or moisture, will be maintained consistent with the current licensing basis through the period of extended operation. The applicant also stated that calibration testing and system performance monitoring are currentlybeing performed for in scope radiation monitoring circuits. The applicant further stated that direct cable testing will be performed as an enhancement to ensure that the cable and connection insulation resistance is adequate for the in scope nuclear instrumentation circuits to perform their intended functions. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the enhancement to determine whether the AMP, with the enhancement, is adequate to manage the aging effects for which the LRA credits it.In comparing the elements in the applicant's program to those in GALL AMP XI.E2, the staff determined that the program elements for which the applicant claimed consistency with the GALL Report, are consistent, with an enhancement. The staff identified an issue in the "scope ofprogram" program element that required additional information. In the "scope of program" program element, GALL AMP XI.E2 states this program applies to electrical cables and connections (cable system) used in circuits with sensitive, high voltage, low level signals such as radiation monitoring and nuclear instrumentation. The staff noted that theapplicant excluded the incore monitoring system from the scope of the program. In RAI B.2.1.31-1, dated October 07, 2008, the staff requested that the applicant provide additional information as to why the incore monitoring system is not in scope of license renewal.In its response to the RAI dated October 30, 2008, the applicant stated that the Incore Monitoring System circuits that are in scope for license renewal are included in the Environmental Qualification (EQ) of Electrical Components Program. The applicant also stated that because the Incore Monitoring System circuits that are in scope have their potential aging effects managed by the EQ of Electrical Components Program, these circuits are not included in the scope of this AMP.Based on its review, the staff finds the applicant's response to RAI B.2.1.31-1 acceptable because the applicant has provided adequate basis to justify not including the incore monitoring system in the scope of this AMP. The staffs concern discussed in RAI B.2.1.31-1 is resolved.Enhancement. The LRA states an enhancement to the GALL Report as follows: The TMI-1 Electrical Cables and Connections Not Subject to 10 CFR 50.59 Environmental Qualification Requirements Used In Instrumentation Circuits aging management program 3-113 3.0.3.2.22 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Summary of Technical Information in the Application. LRA Section B.2.1.31 describes the existing Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program as being consistent, with an enhancement, with GALL AMP XI.E2, "Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits." The applicant stated that this program will provide reasonable assurance that the intended functions of electrical cables that are not subject to the environmental qualification requirements of 10 CFR 50.49 and are used in instrumentation circuits with sensitive, high voltage, low-level signals exposed to adverse localized environments caused by heat, radiation or moisture, will be maintained consistent with the current licensing basis through the period of extended operation. The applicant also stated that calibration testing and system performance monitoring are currently being performed for in scope radiation monitoring circuits. The applicant further stated that direct cable testing will be performed as an enhancement to ensure that the cable and connection insulation resistance is adequate for the in scope nuclear instrumentation circuits to perform their intended functions. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the enhancement to determine whether the AMP, with the enhancement, is adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in GALL AMP XI.E2, the staff determined that the program elements for which the applicant claimed consistency with the GALL Report, are consistent, with an enhancement. The staff identified an issue in the "scope of program" program element that required additional information. In the "scope of program" program element, GALL AMP XI.E2 states this program applies to electrical cables and connections (cable system) used in circuits with sensitive, high voltage, low level signals such as radiation monitoring and nuclear instrumentation. The staff noted that the applicant excluded the incore monitoring system from the scope of the program. In RAI B.2.1.31-1, dated October 07, 2008, the staff requested that the applicant provide additional information as to why the incore monitoring system is not in scope of license renewal. In its response to the RAI dated October 30, 2008, the applicant stated that the Incore Monitoring System circuits that are in scope for license renewal are included in the Environmental Qualification (EQ) of Electrical Components Program. The applicant also stated that because the Incore Monitoring System circuits that are in scope have their potential aging effects managed by the EO of Electrical Components Program, these circuits are not included in the scope of this AMP. Based on its review, the staff finds the applicant's response to RAI B.2.1.31-1 acceptable because the applicant has provided adequate basis to justify not including the incore monitoring system in the scope of this AMP. The staff's concern discussed in RAI B.2.1.31-1 is resolved. Enhancement. The LRA states an enhancement to the GALL Report as follows: The TMI-1 Electrical Cables and Connections Not Subject to 10 CFR 50.59 Environmental Qualification Requirements Used In Instrumentation Circuits aging management program 3-113 is an existing program that will be enhanced. In scope radiation monitoring circuits are currently tested in alignment with NUREG-1801 aging management program XI.E2, Electrical Cables and Connections Not Subject to 10 CR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits. Existing testing practices will be enhanced by performing direct cable testing for in scope nuclear instrument circuits.By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects," and "acceptance criteria" program elements.LRA Section B.2.1.31 states that the Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program, when enhanced, is consistent with GALL AMP XI.E2. The applicant also stated that the methods of testing are calibration testing and system performance monitoring which are being performed for in scope radiation monitoring circuits. The applicant also stated that direct cable testing will be performed once every 10 years as an enhancement to ensure cable and connection insulation resistance is adequate for in scope nuclear instrumentation circuits to perform their intended functions. Based on its review, the staff finds the enhancement acceptable because it will make the applicant's Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program consistent with GALL AMP Xl. E2.Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.31 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant stated that instrument circuit calibrations for the in-scope radiation monitoring circuits are part of surveillance testing and preventive maintenance that is currently being conducted. The staff did not identify any significant events attributed to insulation degradation nor is there a trend indicating age degradation. The applicant also stated that as an enhancement, the applicant will implement direct cable tests for the in-scope nuclear instrumentation circuits. This testing is to be added as an enhancement to existing practices, which include periodic electronic component calibration and heat balance computation. Recent operating experience with nuclear instrumentation circuits has resulted in a planned plant change for the replacement of the penetration for the Nuclear Instrument NI-12 source/wide range nuclear instrumentation to correct degraded penetration triaxial connectors. This issue is documented, evaluated and corrected via the corrective action program. The staff confirmed that the applicant had appropriately identified the appropriate root causes of cable aging and took appropriate corrective actions. The staff also reviewed the issue reports on these events in the license renewal basis binder. The staff determined that the issue reports demonstrated that the applicant had implemented appropriate corrective actions.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. 3-114 is an existing program that will be enhanced. In scope radiation monitoring circuits are currently tested in alignment with NUREG-1801 aging management program XI.E2, Electrical Cables and Connections Not Subject to 10 CR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits. Existing testing practices will be enhanced by performing direct cable testing for in scope nuclear instrument circuits. By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects," and "acceptance criteria" program elements. LRA Section B.2.1.31 states that the Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program, when enhanced, is consistent with GALL AMP XI.E2. The applicant also stated that the methods of testing are calibration testing and system performance monitoring which are being performed for in scope radiation monitoring circuits. The applicant also stated that direct cable testing will be performed once every 10 years as an enhancement to ensure cable and connection insulation resistance is adequate for in scope nuclear instrumentation circuits to perform their intended functions. Based on its review, the staff finds the enhancement acceptable because it will make the applicant's Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program consistent with GALL AMP XI.E2. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.31 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The applicant stated that instrument circuit calibrations for the in-scope radiation monitoring circuits are part of surveillance testing and preventive maintenance that is currently being conducted. The staff did not identify any significant events attributed to insulation degradation nor is there a trend indicating age degradation. The applicant also stated that as an enhancement, the applicant will implement direct cable tests for the in-scope nuclear instrumentation circuits. This testing is to be added as an enhancement to existing practices, which include periodic electronic component calibration and heat balance computation. Recent operating experience with nuclear instrumentation circuits has resulted in a planned plant change for the replacement of the penetration for the Nuclear Instrument NI-12 source/wide range nuclear instrumentation to correct degraded penetration triaxial connectors. This issue is documented, evaluated and corrected via the corrective action program. The staff confirmed that the applicant had appropriately identified the appropriate root causes of cable aging and took appropriate corrective actions. The staff also reviewed the issue reports on these events in the license renewal basis binder. The staff determined that the issue reports demonstrated that the applicant had implemented appropriate corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1 O. The staff finds this program element acceptable. 3-114 UFSAR Supplement. LRA Section A.2.1.31 provides the applicant's UFSAR Supplement for the Electrical Cables and Connections Not Subject To 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR.In LRA Section A.5, Commitment No. 31, the applicant committed to implement the program enhancement prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Electrical Cables and Connections Not Subject To 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its audit and review of the applicant's Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program, the staff finds all program elements for which the applicant claimed consistency with the GALL Report, are consistent with the implementation of an enhancement. The staff reviewed the enhancement and its justification and finds that the AMP, with the enhancement, is adequate to manage the aging_ effects for which the LRA credits it. The staff concludes that the applicant has demonstrated that effects of aging will be adequatelymanaged so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.23 Metal Enclosed Bus Summary of Technical Information in the Application. LRA Section B.2.1.33 describes the existing Metal Enclosed Bus Program as being consistent, with enhancement, to GALL AMP XI.E4, "Metal Enclosed Bus." The applicant stated that the program will be managing the aging of metal enclosed buses. The applicant also states that a sample of accessible bolted connections will be checked for loose connections via thermography, which is an existing predictive maintenance activity. The applicant also stated that a sample of in scope metal enclosed bus internals is currently visually inspected and that this program, including its enhancements, will be implemented prior to the period of extended operation so that the intended functions of components within the scope of license renewal will be maintained during the period of extended operation. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the enhancement to determine whether the AMP, with the enhancement, is adequate to manage the aging effects for which the LRA credits it.In comparing the elements in the applicant's program to those in GALL AMP XI.E4, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent, with an enhancement. 3-115 UFSAR Supplement. LRA Section A.2.1.31 provides the applicant's UFSAR Supplement for the Electrical Cables and Connections Not Subject To 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR. In LRA Section A.5, Commitment No. 31, the applicant committed to implement the program enhancement prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Electrical Cables and Connections Not Subject To 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program, the staff finds all program elements for which the applicant claimed consistency with the GALL Report, are consistent with the implementation of an enhancement. The staff reviewed the enhancement and its justification and finds that the AMP, with the enhancement, is adequate to manage the aging_ effects for which the LRA credits it. The staff concludes that the applicant has demonstrated that effects of aging will be adequately managed so that the intended function( s) will be maintained consistent with the CLB for the period of extended operation as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.23 Metal Enclosed Bus Summary of Technical Information in the Application. LRA Section B.2.1.33 describes the existing Metal Enclosed Bus Program as being consistent, with enhancement, to GALL AMP XI.E4, "Metal Enclosed Bus." The applicant stated that the program will be managing the aging of metal enclosed buses. The applicant also states that a sample of accessible bolted connections will be checked for loose connections via thermography, which is an existing predictive maintenance activity. The applicant also stated that a sample of in scope metal enclosed bus internals is currently visually inspected and that this program, including its enhancements, will be implemented prior to the period of extended operation so that the intended functions of components within the scope of license renewal will be maintained during the period of extended operation. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the enhancement to determine whether the AMP, with the enhancement, is adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in GALL AMP XI.E4, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report, are consistent, with an enhancement. 3-115 Enhancement. The LRA states an enhancement to the GALL Report as follows: Thermography of metal enclosed busses is an existing TMI-1 predictive maintenance activity. A sample of in scope metal enclosed bus internals is currently visually inspected. These inspection activities will be enhanced to specify the following inspection criteria:* Internal portion of the metal enclosed bus will be visually inspected for cracks, corrosion, foreign debris, excessive dust build-up and evidence of moisture intrusion." The bus insulation will be visually inspected for signs of embrittlement, cracking, melting, swelling, or discoloration, which may indicate overheating or aging degradation.

  • The internal bus supports will be visually inspected for structural integrity and signs of cracks.As an additional enhancement, existing metal enclosed bus internal visual inspections will be expanded to include the 480V Metal Enclosed Bus and the Station Black Out Metal Enclosed Bus. This program, including its enhancements, will be implemented prior to the period ofextended operation so that the intended functions of components within the scope of License Renewal will be maintained during the period of extended operation.

By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects," and "corrective actions" program elements.Based on its review, the staff finds the enhancement acceptable because it is consistent with GALL AMP XI.E4 and the AMP, with the enhancement ensures that the effects of aging will be adequately managed.Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.33 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant stated that industry experience has shown failures have occurred on metal enclosed buses caused by cracked insulation and moisture or debris buildup internal to the metal enclosed bus. The applicant also stated that operating experience has also shown that bus connections in the metal enclosed bus exposed to appreciable ohmic heating during operation may experience loosening due to repeated cycling of connected loads. The applicant further stated that NRC Information Notice (IN) 2000-14, "Non Vital Bus Fault Leads to Fire and Loss of Offsite Power" and LER 324-06001, "Manual Scram Following a Loss of Startup Auxiliary Transformer" are examples of non-segregated bus duct failures. The applicant also stated that a specific review of the thermography results from preventive maintenance repetitive tasks and 1A Auxiliary Transformer bus duct internal inspections did not identify a trend related to aging 3-116 Enhancement. The LRA states an enhancement to the GALL Report as follows: Thermography of metal enclosed busses is an existing TMI-1 predictive maintenance activity. A sample of in scope metal enclosed bus internals is currently visually inspected. These inspection activities will be enhanced to specify the following inspection criteria:

  • Internal portion of the metal enclosed bus will be visually inspected for cracks, corrosion, foreign debris, excessive dust build-up and evidence of moisture intrusion.
  • The bus insulation will be visually inspected for signs of embrittlement, cracking, melting, swelling, or discoloration, which may indicate overheating or aging degradation.
  • The internal bus supports will be visually inspected for structural integrity and signs of cracks. As an additional enhancement, existing metal enclosed bus internal visual inspections will be expanded to include the 480V Metal Enclosed Bus and the Station Black Out Metal Enclosed Bus. This program, including its enhancements, will be implemented prior to the period of extended operation so that the intended functions of components within the scope of License Renewal will be maintained during the period of extended operation.

By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects," and "corrective actions" program elements. Based on its review, the staff finds the enhancement acceptable because it is consistent with GALL AMP XI.E4 and the AMP, with the enhancement ensures that the effects of aging will be adequately managed. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.33 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. The applicant stated that industry experience has shown failures have occurred on metal enclosed buses caused by cracked insulation and moisture or debris buildup internal to the metal enclosed bus. The applicant also stated that operating experience has also shown that bus connections in the metal enclosed bus exposed to appreciable ohmic heating during operation may experience loosening due to repeated cycling of connected loads. The applicant further stated that NRC Information Notice (IN) 2000-14, "Non Vital Bus Fault Leads to Fire and Loss of Offsite Power" and LER 324-06001, "Manual Scram Following a Loss of Startup Auxiliary Transformer" are examples of non-segregated bus duct failures. The applicant also stated that a specific review of the thermography results from preventive maintenance repetitive tasks and 1 A Auxiliary Transformer bus duct internal inspections did not identify a trend related to aging 3-116 degradation. A search of its corrective action database by the applicant has revealed no failuresof metal closed buses.Based on the review of the industry and applicant-identified operating experience, the staff has confirmed that the applicant has addressed operating experience related to this program, and has identified the applicable aging effects, i.e., loosening of bus connections, moisture or debris buildup internal to the metal enclosed bus, which are the aging effects identified in the GALL Report for this program.The staff confirmed 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. LRA Section A.2.1.33 provides the applicant's UFSAR Supplement for the Metal Enclosed Bus Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staffs recommended UFSAR Supplement guidance found in the SRP-LR.In LRA Section A.5, Commitment No. 33, the applicant committed to the program enhancement relating to visual inspections prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Metal Enclosed Bus Program as required by 10 CFR 54.21(d).Conclusion. On the basis of its audit and review of the applicant's Metal Enclosed Bus Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the enhancement and its justification, and finds that with its implementation through Commitment No. 33 prior to the period of extended operation, the existing program will be consistent with the GALL AMP with which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.24 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Summary of Technical Information in the Application. LRA Section B.2.1.34 describes the new Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program as being consistent, with an exception, with GALL AMP XI.E6, "Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements." The applicant stated that the program will be used to manage the aging effects of metallic parts of cable connections. The applicant stated that a representative sample of cable connections within the scope of license renewal will be selected for one-time testing prior to the period of extended operation to confirm that there is no age-related degradation of the electrical connection metallic parts. The applicant also stated that the scope of this sampling program will consider application (medium and low voltage), circuit loading (high loading), and location (high temperature, high humidity, vibration, etc) and that the technical basis for the sample selection will be documented.The applicant further stated that the specific type of test performed will be a proven test for 3-117 degradation. A search of its corrective action database by the applicant has revealed no failures of metal closed buses. Based on the review of the industry and applicant-identified operating experience, the staff has confirmed that the applicant has addressed operating experience related to this program, and has identified the applicable aging effects, i.e., loosening of bus connections, moisture or debris buildup internal to the metal enclosed bus, which are the aging effects identified in the GALL Report for this program. The staff confirmed the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1

o. The staff finds this program element acceptable.

UFSAR Supplement. LRA Section A.2.1.33 provides the applicant's UFSAR Supplement for the Metal Enclosed Bus Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR. In LRA Section A.5, Commitment No. 33, the applicant committed to the program enhancement relating to visual inspections prior to the period of extended operation. The staff finds thatthe applicant has provided an adequate summary description of the Metal Enclosed Bus Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Metal Enclosed Bus Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the enhancement and its justification, and finds that with its implementation through Commitment No. 33 prior to the period of extended operation, the existing program will be consistent with the GALL AMP with which it was compared. The concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function( s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.24 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Summary of Technical Information in the Application. LRA Section B.2.1.34 describes the new Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program as being consistent, with an exception, with GALL AMP XI.E6, "Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements." The applicant stated that the program will be used to manage the aging effects of metallic parts of cable connections. The applicant stated that a representative sample of cable connections within the scope of license renewal will be selected for one-time testing prior to the period of extended operation to confirm that there is no age-related degradation of the electrical connection metallic parts. The applicant also stated that the scope of this sampling program will consider application (medium and low voltage), circuit loading (high loading), and location (high temperature, high humidity, vibration, etc) and that the technical basis for the sample selection will be documented. The applicant further stated that the specific type of test performed will be a proven test for 3-117 detecting loose connections, such as thermography or contact resistance measurement, as appropriate to the application. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, remained adequate to manage the aging effect for which the LRA credits it.In comparing the elements in the applicant's program to those in GALL AMP XI.E6, the staff determined that the program elements for which the applicant claimed consistency with the GALL Report, are consistent, with an exception. Exception. The LRA states an exception to the GALL Report as follows: NUREG-1801 describes an aging management program for electrical cable connections in Chapter XI: XI.E6 "Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements." An NRC and industry effort is in progress, working towards the issuance of a revision to XI.E6, via the Interim Staff Guidance (ISG)process. The latest draft revision of this ISG was presented for public comment in the September 6, 2007, Vol. 72, No. 172 issue of the Federal Register as: Proposed License Renewal Interim Staff Guidance LR-ISG-2007-02: Changes to Generic Aging Lessons Learned (GALL) Report Aging Management Program (AMP) XI.E6, "Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements" Solicitation of Public Comment. The exception for this aging management program is that the TMI-1 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements aging management program is consistent with NUREG-1801 as it is modified by the September 6, 2007 draft revision of LR-ISG-2007-02. By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects," and "corrective actions" program elements.The staff issued draft LR-ISG-2007-02 on September 6, 2007 for public comments. In this ISG, the staff clarifies and recommends a one-time inspection to ensure that either aging of metallic cable connections is not occurring or an existing maintenance program is effective. Upon receiving public comments, the staff will evaluate comments and make a determination to incorporate comments, as appropriate. Once the staff completes the LR-ISG, it will issue it for industry use. The staff will incorporate the approved LR-ISG into the next revision of the license renewal guidance document. Until then, the staff will compare the elements of applicant's Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program against those currently in GALL AMP XI.E6. Any deviation from GALL AMP XI.E6 will require the applicant's identification for each exception and element affected. Thestaff noted that the applicant did not identify each specific exception or provide specific justification for each exception. Additionally, the applicant did not provide the program elements associated with each exception. In RAI B.2.1.34-1, the staff requested that the applicant provide additional information to describe each exception and provide the program elements associated with each exception. In its response to the RAI dated October 30, 2008, the applicant stated that differences between the GALL XI.E6 AMP and the proposed revision via the September 2007 draft of LR-ISG-2007-3-118 detecting loose connections, such as thermography or contact resistance measurement, as appropriate to the application. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GAll Report. The staff reviewed the exception to determine whether the AMP, with the exception, remained adequate to manage the aging effect for which the lRA credits it. In comparing the elements in the applicant's program to those in GAll AMP XI.E6, the staff determined that the program elements for which the applicant claimed consistency with the GAll Report, are consistent, with an exception. Exception. The lRA states an exception to the GAll Report as follows: NUREG-1801 describes an aging management program for electrical cable connections in Chapter XI: XI.E6 "Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements." An NRC and industry effort is in progress, working towards the issuance of a revision to XI.E6, via the Interim Staff Guidance (ISG) process. The latest draft revision of this ISG was presented for public comment in the September 6, 2007, Vol. 72, No. 172 issue of the Federal Register as: Proposed license Renewal Interim Staff Guidance lR-ISG-2007 -02: Changes to Generic Aging lessons learned (GAll) Report Aging Management Program (AMP) XI.E6, "Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements" Solicitation of Public Comment. The exception for this aging management program is that the TMI-1 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements aging management program is consistent with NUREG-1801 as it is modified by the September 6,2007 draft revision of lR-ISG-2007-02. By letter dated October 30, 2008, the applicant stated that this exception applies to the "scope of program," "parameters monitored/inspected," "detection of aging effects," and "corrective actions" program elements. The staff issued draft lR-ISG-2007-02 on September 6,2007 for public comments. In this ISG, the" staff clarifies and recommends a one-time inspection to ensure that either aging of metallic cable connections is not occurring or an existing maintenance program is effective. Upon receiving public comments, the staff will evaluate comments and make a determination to incorporate comments, as appropriate. Once the staff completes the lR-ISG, it will issue it for industry use. The staff will incorporate the approved lR-ISG into the next revision of the license renewal guidance document. Until then, the staff will compare the elements of applicant's Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program against those currently in GAll AMP XI.E6. Any deviation from GAll AMP XI.E6 will require the applicant's identification for each exception and element affected. The staff noted that the applicant did not identify each specific exception or provide specific justification for each exception. Additionally, the applicant did not provide the program elements associated with each exception. In RAI B.2.1.34-1, the staff requested that the applicant provide additional information to describe each exception and provide the program elements associated with each exception. In its response to the RAI dated October 30, 2008, the applicant stated that differences between the GAll XI.E6 AMP and the proposed revision via the September 2007 draft of lR-ISG-2007-3-118 02, as relevant to Elements 1, 3, 4 and 7, include the following points of exception to the GALL XI.E6 AMP: (1) This program includes external cable connections terminating at an active device. The program does not include wiring connections internal to an active assembly. This program does not include high voltage (>35 kV) switchyard connections. (AMP Element 1, Scope of Program).(2) In-scope cable connections are evaluated for applicability of this program. The sample for the one-time inspection will be taken from cable connections, in scope for license renewal, that are not subject to 10 CFR 50.49 environmental qualification requirements. Factors considered in selection of the sample will include application (medium and low voltage),circuit loading (high loading), and location (high temperature, high humidity, vibration, etc.). (AMP Element 3, Parameters Monitored or Inspected). (3) The TMI-1 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements aging management program is a one-time inspection, on a sampling basis. The intent of the one-time inspection is to confirm the absence of age-related degradation of cable connections (metallic parts). (Program Element 4, Detection of Aging Effects).Based on its review, the staff finds the applicant's response to RAI B.2.1.34-1 acceptable and also finds the exception to the "scope of program" program element acceptable because the exception is consistent with what is proposed in the final revision of LR-ISG-2007-02. The staff noted that the connections internal to an active assembly are considered part of the active assembly and do not require an AMR. The exclusion of high voltage connections (>35 kV) in the"scope of program" program element is acceptable because high voltage connections are addressed elsewhere in the SER under switchyard connections. The staff's concern described in RAI B.2.1.34-1 is resolved.Based on its review, the staff finds the exception to the "parameters monitored or inspected," program element acceptable because the exception is consistent with the staff's clarifications provided in LR-ISG-2007-02, because the sample of connections considered does not include the high-voltage application and low circuit loading and because the aging effect of loosening of cable connections due to thermal cycling is insignificant for low load circuits because of low current. Thestaff noted that high-voltage connections are addressed elsewhere in the SER under switchyard connections. Based on its review, the staff finds the exception to the "detection of aging effects" program element acceptable. The staff noted that this is a one-time inspection on a sampling basis instead of periodic inspections as currently recommended in GALL AMP XI.E6. In reviewing operating experience to address industrial comments about GALL AMP XI.E6, the staff finds that few operating experiences related to failed connections are due to human errors or maintenance practices. The staff noted that the operating experience can't support a periodic inspection as currently recommended in GALL AMP XI.E6. However, because there have been a limited number of age related failures of cable connections, a one-time inspection of the metallic portion of electrical cable connections is warranted. On this basis, the staff issued LR-ISG-2007-02 to provide clarification and recommend a one-time inspection, on a representative sampling basis, to 3-119 02, as relevant to Elements 1, 3, 4 and 7, include the following points of exception to the GALL XLE6 AMP: {1} . This program includes external cable connections terminating at an active device. The program does not include wiring connections internal to an active assembly. This program does not include high voltage (>35 kV) switchyard connections. (AMP Element 1, Scope of Program). (2) In-scope cable connections are evaluated for applicability of this program. The sample for the one-time inspection will be taken from cable connections, in scope for license renewal, that are not subject to 10 CFR 50.49 environmental qualification requirements. Factors considered in selection of the sample will include application (medium and low voltage), circuit loading (high loading), and location (high temperature, high humidity, vibration, etc.). (AMP Element 3, Parameters Monitored or Inspected). (3) The TMI-1 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements aging management program is a one-time inspection, on a sampling basis. The intent of the one-time inspection is to confirm the absence of related degradation of cable connections (metallic parts). (Program Element 4, Detection of Aging Effects). Based on its review, the staff finds the applicant's response to RAI B.2.1.34-1 acceptable and also finds the exception to the "scope of program" program element acceptable because the exception is consistent with what is proposed in the final revision of LR-ISG-2007 -02. The staff noted that the connections internal to an active assembly are considered part of the active assembly and do not require an AMR. The exclusion of high voltage connections (>35 kV) in the "scope of program" program element is acceptable because high voltage connections are addressed elsewhere in the SER under switchyard connections. The staff's concern described in RAI B.2.1.34-1 is resolved. Based on its review, the staff finds the exception to the "parameters monitored or inspected," program element acceptable because the exception is consistent with the staff's clarifications provided in LR-ISG-2007-02, because the sample of connections considered does not include the high-voltage application and low circuit loading and because the aging effect of loosening of cable connections due to thermal cycling is insignificant for low load circuits because of low current. The staff noted that high-voltage connections are addressed elsewhere in the SER under switchyard connections. Based on its review, the staff finds the exception to the "detection of aging effects" program element acceptable. The staff noted that this is a one-time inspection on a sampling basis instead of periodic inspections as currently recommended in GALL AMP XLE6. In reviewing operating experience to address industrial comments about GALL AMP XLE6, the staff finds that few operating experiences related to failed connections are due to human errors or maintenance practices. The staff noted that the operating experience can't support a periodic inspection as currently recommended in GALL AMP XLE6. However, because there have been a limited number of age related failures of cable connections, a one-time inspection of the metallic portion of electrical cable connections is warranted. On this basis, the staff issued LR-ISG-2007-02 to provide clarification and recommend a one-time inspection, on a representative sampling basis, to 3-119 ensure that either aging of metallic cable connections is not occurring or existing preventive maintenance is effective, such that a periodic inspection is not needed.The applicant amended the LRA to incorporate the exceptions as discussed above. The applicant also amended the LRA to include the following in the "discussion" column of Table 3.6.1: Consistent with NUREG-1 801 with exceptions. The Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements aging management program, B.2.1.34, will be used to manage loosening of bolted connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation of the metallic parts of cable connections. The applicant also amended LRA Table 3.6.2-1, Electrical Commodities, Summary of Aging Management Evaluation, line item for Cable Connections (Metallic Parts) by changing the Notes column from "A" to "B." Based on its review, the staff finds that the AMP, with the exceptions, is adequate to manage the aging effect for which it is credited.Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.34 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.In LRA Section B.2.1.34, the applicant stated that in April 2002, a phase terminal hot spot was discovered by an operator on rounds. The applicant stated that it appears the connectionloosened due to heating and or vibration. After this event, the Exelon corporate Thermography Program Guide (MA-AA-716-230-1003) was implemented. The applicant also stated that in March of 2003, thermography revealed that a hot spot on a breaker load side connection existed. The"B" phase connection was 90 C hotter than the "A" and "C" phase due to a slightly loose lug. The applicant further stated that in December of 2004, thermography revealed the line side connection was 110 C hotter than the "A" and "B" phases as a result of a loosely crimped lug.Based on the staffs review of the applicant-identified operating experience, the staff has confirmed that the applicant has addressed operating experience related to this program, and has identified the applicable aging effects, i.e., loosening of cable connections, which is the aging effect identified by GALL for this program. The staff finds that this demonstrates that the existing maintenance program is effective to detect degraded connections and take appropriate corrective actions before component failures.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. LRA Section A.2.1.34 provides the applicant's UFSAR Supplement for the Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR. 3-120 ensure that either aging of metallic cable connections is not occurring or existing preventive maintenance is effective, such that a periodic inspection is not needed. The applicant amended the LRA to incorporate the exceptions as discussed above. The applicant also amended the LRA to include the following in the "discussion" column of Table 3.6.1: Consistent with NUREG-1801 with exceptions. The Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements aging management program, B.2.1.34, will be used to manage loosening of bolted connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation of the metallic parts of cable connections. The applicant also amended LRA Table 3.6.2-1, Electrical Commodities, Summary of Aging Management Evaluation, line item for Cable Connections (Metallic Parts) by changing the Notes column from "A" to "B." Based on its review, the staff finds that the AMP, with the exceptions, is adequate to manage the aging effect for which it is credited. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.2.1.34 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. In LRA Section B.2.1.34, the applicant stated that in April 2002, a phase terminal hot spot was discovered by an operator on rounds. The applicant stated that it appears the connection loosened due to heating and or vibration. After this event, the Exelon corporate Thermography Program Guide (MA-AA-716-230-1003) was implemented. The applicant also stated that in March of 2003, thermography revealed that a hot spot on a breaker load side connection existed. The "B" phase connection was 9 0 C hotter than the "A" and "C" phase due to a slightly loose lug. The applicant further stated that in December of 2004, thermography revealed the line side connection was 11 0 C hotter than the "A" and "B" phases as a result of a loosely crimped lug. Based on the staff's review of the applicant-identified operating experience, the staff has confirmed that the applicant has addressed operating experience related to this program, and has identified the applicable aging effects, i.e., loosening of cable connections, which is the aging effect identified by GALL for this program. The staff finds that this demonstrates that the existing maintenance program is effective to detect degraded connections and take appropriate corrective actions before component failures. The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1

o. The staff finds 'this program element acceptable.

UFSAR Supplement. LRA Section A.2.1.34 provides the applicant's UFSAR Supplement for the Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR. 3-120 In LRA Section A.5, Commitment No. 34, the applicant committed to implement the program prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the ElectricalCable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its audit and review of the applicant's Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirement Program, and the applicant's response to the RAI, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exceptions and determined that the AMP, with the exceptions, is adequate to manage the aging effects for which it is credited. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.2.25 Metal Fatigue of Reactor Coolant Pressure Boundary Summary of Technical Information in the Application. LRA Section B.3.1.1 describes the existing Metal Fatigue of Reactor Coolant Pressure Boundary Program as being consistent, with an enhancement, to GALL AMP X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary." The applicant states that the program is credited for managing fatigue of reactor coolant pressure boundary components and other components. The AMP tracks the number of occurrences of significant thermal and pressure transients and compares the cumulative cycles to the number of design cycles. To assure staying within the pre-determined cycle limits, the applicant stated that the AMP enforces corrective actions if the cumulative cycle counts of any transient approaches either 80% of the design cycle limit, or 80% of the administrative cycle limit.The applicant further stated environmental fatigue effects have been addressed by evaluating the sample components identified in NUREG/CR-6260 as being applicable to the plant. The applicant calculated the Fen values for each of the sample NUREG/CR-6260 components based on the methods shown in NUREG/CR-6583 and in NUREG/CR-5704 for carbon steel, low-alloy steel and stainless steel. Multiplying the Fen values by a factor of 1.5 and by the design CUF values of the corresponding components, the applicant obtained the Environmentally Adjusted Fatigue (EAF) usage factors. The staff noted that the applicant introduced the 1.5 factor in the calculations to account for the period of extended operation so that the final products are EAF-adjusted CUF values good for 60 years. Since these components would have fatigue usage that exceeds 1.0 if the transient cycle limits were increased to 1.5 times the current design limits, the program will maintain the current transient cycle design limits to manage fatigue during the period of extended operation. Since for certain components the projected 60-year EAF-adjusted CUF values exceed the fatigue limit, the applicant performed additional fatigue evaluations for these components to establish a set of new transient cycle administrative limits which would result in acceptable EAF-adjusted CUF values during the period of the extended operation. The applicant stated that the new administrative cycle limits will be incorporated into the Metal Fatigue of Reactor Coolant PressureBoundary Program prior to the period of the extended operation. 3-121 In LRA Section A.5, Commitment No. 34, the applicant committed to implement the program prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirement Program, and the applicant's response to the RAI, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exceptions and determined that the AMP, with the exceptions, is adequate to manage the aging effects for which it is credited. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that it provides an* adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.25 Metal Fatigue of Reactor Coolant Pressure Boundary Summary of Technical Information in the Application. LRA Section B.3.1.1 describes the existing Metal Fatigue of Reactor Coolant Pressure Boundary Program as being consistent, with an enhancement, to GALL AMP X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary." The applicant states that the program is credited for managing fatigue of reactor coolant pressure boundary components and other components. The AMP tracks the number of occurrences of significant thermal and pressure and compares the cumulative cycles to the number of deSign cycles. To assure staying within the pre-determined cycle limits, the applicant stated that the AMP enforces corrective actions if the cumulative cycle counts of any transient approaches either 80% of the design cycle limit, or 80% of the administrative cycle limit. The applicant further stated environmental fatigue effects have been addressed by evaluating the sample components identified in NUREG/CR-6260 as being applicable to the plant. The applicant calculated the Fen values for each of the sample NUREG/CR-6260 components based on the methods shown in NUREG/CR-6583 and in NUREG/CR-5704 for carbon steel, low-alloy steel and stainless steel. Multiplying the Fen values by a. factor of 1.5 and by the design CUF values of the corresponding components, the applicant obtained the Environmentally Adjusted Fatigue (EAF) usage factors. The staff noted that the applicant introduced the 1.5 factor in the calculations to account for the period of extended operation so that the final products are EAF-adjusted CUF values good for 60 years. Since these components would have fatigue usage that exceeds 1.0 if the transient cycle limits were increased to 1.5 times the current design limits, the program will maintain the current transient cycle design limits to manage fatigue during the period of extended operation. Since for certain components the projected 60-year EAF-adjusted CUF values exceed the fatigue limit, the applicant performed additional fatigue evaluations for these components to establish a set of new transient cycle administrative limits which would result in acceptable EAF-adjusted CUF values during the period of the extended operation. The applicant stated that the new administrative cycle limits will be incorporated into the Metal Fatigue of Reactor Coolant Pressure Boundary Program prior to the period of the extended operation. 3-121 Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the enhancement to determine whether the AMP, with the enhancement, is adequate to manage the aging effects for which the LRA credits it.In comparing the elements in the applicant's program to those in GALL AMP XI.M1, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent, with an enhancement. This AMP relies on transient cycle monitoring to evaluate the fatigue usage described in the LRA.The applicant stated that this approach tracks the number of occurrences of significant thermal and pressure transients (significant events) and compares the cumulative cycles, projected to cover the renewal period, against the number of design cycles specified in the design specifications. The applicant uses the projected cycles to evaluate the total cumulative usage factor for 60 years. The staff noted that for this approach to work, none of the significant events tracked should produce stresses greater than those that would be produced by the design transients, not just the number of cycles alone. Specifically, the staff notes, the P-T (Pressure and Temperature) characteristics, including their values, ranges, and rates, must all be bounded within those defined in the design specifications. The staff determined that additional information was required to complete the review. In RAI B.3.1.1-1, dated September 29, 2008, the staff requested that the applicant provide additional information regarding its justification that the monitored transient data remains bounded by those defined in the design specification. In its response to the RAI, dated October 20, 2008, the applicant stated that the plant fatigue monitoring procedure provides detailed design transient definitions that characterize each monitored design transient event. The applicant further stated the Control Room Operators review the monitored data during the logging of a transient in accordance with the plant fatigue monitoring procedures to confirm that the tracked events do not produce stresses greater than those produced by the design transients. The applicant further stated that the fatigue monitoring procedure requires the Fatigue Monitoring Engineer to review the plant operating logs semi-annually and whenever an unusual reactor operating event occurs that would require abnormal coolant injections. The applicant also stated that plant logs and instrument data from the plant computer are used to assure that the actual transients have been appropriately characterized and are bounded by the design transients. If the plant process parameters (P, T and Flow rates) are not bounded by a design basis transient, as the applicant indicates, or if any tracked transient approaches 80% of its design cycle limit, the fatigue monitoring engineer is required to notify the Engineering Program Manager, initiate an engineering evaluation of the condition and determine the required corrective action.Based on its review, the staff finds the applicant's response to RAI B.3.1.1-1 acceptable because the operational procedures that the applicant adopts for the transient events tracking are consistent with the GALL Report and conservative to ensure a valid cycle-based fatigue management program. The staffs concern described in RAI B.3.1.1-1 is resolved.Enhancement. The LRA states an enhancement to the GALL Report as follows: The TMI-1 Metal Fatigue of Reactor Coolant Pressure Boundary program will be enhanced to add the statement: "Acceptable corrective actions include: reanalysis of the component to demonstrate that the design code limit will not be exceeded prior to or during the period 3-122 Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the enhancement to determine whether the AMP, with the enhancement, is adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in GALL AMP XI.M1, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent, with an enhancement. This AMP relies on transient cycle monitoring to evaluate the fatigue usage described in the LRA. The applicant stated that this approach tracks the number of occurrences of significant thermal and pressure transients (significant events) and compares the cumulative cycles, projected to cover the renewal period, against the number of design cycles specified in the design specifications. The applicant uses the projected cycles to evaluate the total cumulative usage factor for 60 years. The staff noted that for this approach to work, none of the significant events tracked should produce stresses greater than those that would be produced by the design transients, not just the number of cycles alone. Specifically, the staff notes, the P-T (Pressure and Temperature) characteristics, including their values, ranges, and rates, must all be bounded within those defined in the design specifications. The staff determined that additional information was required to complete the review. In RAI B.3.1.1-1, dated September 29, 2008, the staff requested that the applicant provide additional information regarding its justification that the monitored transient data remains bounded by those defined in the design specification. In its response to the RAI, dated October 20, 2008, the applicant stated that the plant fatigue monitoring procedure provides detailed design transient definitions that characterize each monitored design transient event. The applicant further stated the Control Room Operators review the monitored data during the logging of a transient in accordance with the plant fatigue monitoring procedures to confirm that the tracked events do not produce stresses greater than those produced by the design transients. The applicant further stated that the fatigue monitoring procedure requires the Fatigue Monitoring Engineer to review the plant operating logs semi-annually and whenever an unusual reactor operating event occurs that would require abnormal coolant injections. The applicant also stated that plant logs and instrument data from the plant computer are used to assure that the actual transients have been appropriately characterized and are bounded by the design transients. If the plant process parameters (P, T and Flow rates) are not bounded by a design basis transient, as the applicant indicates, or if any tracked transient approaches 80% of its design cycle limit, the fatigue monitoring engineer is required to notify the Engineering Program Manager, initiate an engineering evaluation of the condition and determine the required corrective action. Based on its review, the staff finds the applicant's response to RAI B.3.1.1-1 acceptable because the operational procedures that the applicant adopts for the transient events tracking are consistent with the GALL Report and conservative to ensure a valid cycle-based fatigue management program. The staffs concern described in RAI B.3.1.1-1 is resolved. Enhancement. The LRA states an enhancement to the GALL Report as follows: The TMI-1 Metal Fatigue of Reactor Coolant Pressure Boundary program will be enhanced to add the statement: "Acceptable corrective actions include: reanalysis of the component to demonstrate that the design code limit will not be exceeded prior to or during the period 3-122 of extended operation; repair of the component; replacement of the component, or other methods approved by the NRC." In addition, the program will be enhanced to require areview of additional reactor coolant pressure boundary locations if the usage factor for one of the environmental fatigue sample locations approaches its design limit.By letter dated October 30, 2008, the applicant stated that this enhancement applies to the"corrective actions" program element.The staff determined that each of the corrective action items listed above has the potential toprevent the usage factor from exceeding the design code limit during the period of extended operation and the staff also confirmed that the applicant has incorporated the enhancements in LRA Section A.5, Commitment No. 37.Based on its review, the staff finds this enhancement acceptable because the program will be consistent with GALL AMP XI.M1 and will provide additional assurance that the effects of aging will be adequately managed.Operating Experience. The staff reviewed the operating experience provided in LRA Section B.3.1.1 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmedthat the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant stated that the TMI-1 control room has maintained a transient cycle logbook which keeps the records of the transients that have occurred throughout the plants operating history.Additional data was recorded for facilitating characterization of transients if a more rigorous analysis should become necessary. The applicant indicates that no transient limits have been approached. The applicant also has revised fatigue analyses to account for unanticipated thermal events thathave been discovered in operating plants. The unanticipated thermal events include thermal stratification transients and thermal striping of piping in the reactor coolant system, identified by NRC IE Bulletin 88-08, and insurge/outsurge transients associated with operation of the pressurizer and pressurizer surge line, as identified by NRC IE Bulletin 88-11. These are thermal events that were not known to the nuclear industry before the issue dates of the Bulletins, and therefore, were not included in the original design analyses. Additionally, the applicant stated that due to modifications in the piping system, the High Pressure Injection (HPI) nozzle analyses were revised to account for a modification in the piping arrangement. The applicant stated that the modification results in revised numbers of cycles, which were incorporated into the monitoring program as revised limits.The staff confirmed 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. LRA Section A.4.3, provides the applicant's UFSAR Supplement for the Metal Fatigue of Reactor Coolant Pressure Boundary Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR.3-123 of extended operation; repair of the component; replacement of the component, or other methods approved by the NRC." In addition, the program will be enhanced to require a review of additional reactor coolant pressure boundary locations if the usage factor for one of the environmental fatigue sample locations approaches its design limit. By letter dated October 30, 2008, the applicant stated that this enhancement applies to the "corrective actions" program element. The staff determined that each of the corrective action items listed above has the potential to prevent the usage factor from exceeding the design code limit during the period of extended operation and the staff also confirmed that the applicant has incorporated the enhancements in LRA Section A.5, Commitment No. 37. Based on its review, the staff finds this enhancement acceptable because the program will be consistent with GALL AMP XI.M1 and will provide additional assurance that the effects of aging will be adequately managed. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.3.1.1 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did riot reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report. . The applicant stated that the TMI-1 control room has maintained a transient cycle logbook which keeps the records of the transients that have occurred throughout the plants operating history. Additional data was recorded for facilitating characterization of transients if a more rigorous analysiS should become necessary. The applicant indicates that no transient limits have been approached. The applicant also has revised fatigue analyses to account for unanticipated thermal events that have been discovered in operating plants. The unanticipated thermal events include thermal stratification transients and thermal striping of piping in the reactor coolant system, identified by NRC IE Bulletin 88-08, and insurge/outsurge transients associated with operation of the pressurizer and pressurizer surge line, as identified by NRC IE Bulletin 88-11. These are thermal events that were not known to the nuclear industry before the issue dates of the Bulletins, and therefore, were not included in the original design analyses. Additionally, the applicant stated that due to modifications in the piping system, the High Pressure Injection (HPI) nozzle analyses were revised to account for a modification in the piping arrangement. The stated that the modification results in revised numbers of cycles, which were incorporated into the monitoring program as revised limits. The staff confirmed the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1

o. The staff finds this program element acceptable.

UFSAR Supplement. LRA Section A.4.3, provides the applicant's UFSAR Supplement for the Metal Fatigue of Reactor Coolant Pressure Boundary Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR. 3-123 In LRA Section A.5, Commitment No. 37, the applicant has committed to the enhancements of corrective actions and the review of additional reactor coolant pressure boundary locations prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Metal Fatigue of Reactor Coolant Pressure Boundary Program as required by 10 CFR 54.21(d).Conclusion. On the basis of its audit and review of the applicant's Metal Fatigue of Reactor Coolant Pressure Boundary Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the enhancement and confirmed that its implementation prior to the period of extended operation through Commitment No. 37 would make the existing AMP consistent with the GALL AMP. The staff also reviewed the response to RAI B.3.1.1-1 and finds it acceptable. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and determined that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.26 Concrete Containment Tendon Prestress Summary of Technical Information in the Application. LRA Section B.3.1.2 describes the existing Concrete Containment Tendon Prestress Program as being consistent, with an exception, to GALL AMP X.S1, "Concrete Containment Tendon Prestress." The applicant stated that the program is part of the ASME Section Xl, Subsection IWL Program and is based on the 1992 Edition, with 1992 Addenda, of the ASME Section XI, Boiler and Pressure Vessel Code, and includes confirmatory actions that monitor loss of containment tendon prestressing forces during the current term and which will continue through the period of extended operation. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP with the exception is adequate to manage the aging effects for which the LRA credits it.In comparing the elements in the applicant's program to those in GALL AMP X.S1, the staffdetermined that those program elements for which the applicant claimed consistency with the GALL Report are consistent, with an exception. Exception. The LRA states an exception to the GALL Report as follows: NUREG-1 801 evaluation specifies that acceptance criteria will normally consist of prescribed lower limit (PLL) and the minimum required value (MRV) calculated based on NRC Regulatory Guide 1.35.1 guidance. TMI-1 takes exception to using PLL as acceptance criteria. TMI-1 revised its program to comply with ASME Section Xl, Subsection IWL, as mandated by 10 CFR 50.55a. Subsection IWL specifies that acceptance criteria be based on the actual design basis (or base value) forces and not the PLL or the base value forces less the upper bound losses. Therefore, IWL requires measured tendon force to be at least 95% of the base value rather than 95% of the significantly smaller PLL specified in Regulatory Guide 1.35. Thus TMI-1 acceptance criteria are more conservative than NUREG-1 801 acceptance criteria.3-124 In LRA Section A.5, Commitment No. 37, the applicant has committed to the enhancements of corrective actions and the review of additional reactor coolant pressure boundary locations prior to the period of extended operation. The staff finds that the applicant has provided an adequate summary description of the Metal Fatigue of Reactor Coolant Pressure Boundary Program as required by 10 CFR S4.21(d). Conclusion. On the basis of its audit and review of the applicant's Metal Fatigue of Reactor Coolant Pressure Boundary Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the enhancement and confirmed that its implementation prior to the period of extended operation through Commitment No. 37 would make the existing AMP consistent with the GALL AMP. The staff also reviewed the response to RAI B.3.1.1-1 and finds it acceptable. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and determined that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.26 Concrete Containment Tendon Prestress Summary of Technical Information in the Application. LRA Section B.3.1.2 describes the existing Concrete Containment Tendon Prestress Program as being consistent, with an exception, to GALL AMP X.S1, "Concrete Containment Tendon Prestress." The applicant stated that the program is part of the ASME Section XI, Subsection IWL Program and is based on the 1992 Edition, with 1992 Addenda, of the ASME Section XI, Boiler and Pressure Vessel Code, and includes confirmatory actions that monitor loss of containment tendon prestressing forces during the current term and which will continue through the period of extended operation. Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP with the exception is adequate to manage the aging effects for which the LRA credits it. In comparing the elements in the applicant's program to those in GALL AMP X.S1, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent, with an exception. Exception. The LRA states an exception to the GALL Report as follows: NUREG-1801 evaluation specifies that acceptance criteria will normally consist of prescribed lower limit (PLL) and the minimum required value (MRV) calculated based on NRC Regulatory Guide 1.35.1 guidance. TMI-1 takes exception to using PLL as acceptance criteria. TMI-1 revised its program to comply with ASME Section XI, Subsection IWL, as mandated by 10 CFR 50.55a. Subsection IWL specifies that acceptance criteria be based on the actual design basis (or base value) forces and not the PLL or the base value forces less the upper bound losses. Therefore, IWL requires measured tendon force to be at least 95% of the base value rather than 95% of the significantly smaller PLL specified in Regulatory Guide 1.35. Thus TMI-1 acceptance criteria are more conservative than NUREG-1801 acceptance criteria. 3-124 By letter dated October 30, 2008, the applicant stated that this exception applies to the"acceptance criteria" program element.The staff noted that GALL AMP X.S1 states that acceptance criteria will normally consist of predicted lower limit (PLL) and the minimum required prestressing force, also called minimum required value (MRV).The staff noted that ASME Section Xl, Subsection IWL requires measured tendon force to be at least 95% of the predicted force. The staff also noted that 95% of the PLL specified in Regulatory Guide 1.35.1 is less than 95% of the actual design basis forces.Based on its review, the staff finds the exception to the GALL Report acceptable because the acceptance criteria established by the applicant are more conservative than the acceptance criteria recommended in the GALL Report.Operating Experience. The staff reviewed the operating experience provided in LRA Section B.3.1.2 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience identified after the issuance of the GALL Report.The applicant explained the operating experience of the Concrete Containment Tendon Prestress Program activities. The staff reviewed historic inspection data from basis documents and noted that the most recent prestress tendon inspections were performed in 1999 and 2004. The staff noted that in 1999, forces were determined for 12 tendons (4 vertical, 5 hoop, 3 dome) during the25 th year surveillance of the reactor building prestressing system and that the 12 tendons constitute a sample of approximately 2% of the total tendon population. The staff noted that the results of the tendon forces were above the 95% of the predicted force at the time of inspection. The staff noted that in 2004, forces were determined for 12 tendons (4 vertical, 5 hoop, 3 dome)during the 30 th year surveillance of the reactor building prestressing system and that the 12 tendons constitute a sample of approximately 2% of the total tendon population. The staff noted that two tendons (V-1 37 & V-1 41) adjacent to tendon V-1 40 were added to the initial sample and subjected to testing because elongation of tendon V-140, measured during re-tensioning of tendons de-tensioned for removal of sample wires for testing, exceeded the acceptance limit. The staff noted that the elongation of tendon V-140 exceeded the 10% limit, a condition attributed toanchor head rotation observed during the re-tensioning process. And as a result, tendons V-137 and V-141 (like V-140, these tendons curve around the equipment opening) were added to the surveillance sample, de-tensioned, and re-tensioned. The staff noted that elongation of the two tendons met the 10% acceptance criterion and elongation of tendon V-1 40 also met the acceptance criterion during the second retensioning. The staff noted that the applicant's engineering evaluation concluded the initial excess elongation of tendon V-140 was acceptable per ASME IWL-3000. The staff agreed with the applicant's engineering evaluation since it followed the acceptance criteria of ASME IWL-3000. Based on its review, the staff finds that the operating experience of the Concrete Containment Tendon Prestress Program did not show any adverse trend in performance and that any problemsidentified, would not cause significant impact to the safe operation of the plant. The staff also finds that adequate corrective actions were taken to prevent recurrence and that appropriate guidance 3-125 By letter dated October 30, 2008, the applicant stated that this exception applies to the "acceptance criteria" program element. The staff noted that GALL AMP X.S1 states that acceptance criteria will normally consist of predicted lower limit (PLL) and the minimum required prestressing force, also called minimum required value (MRV). The staff noted that ASME Section XI, Subsection IWL requires measured tendon force to be at least 95% of the predicted force. The staff also noted that 95% of the PLL specified in Regulatory Guide 1.35.1 is less than 95% of the actual design basis forces. Based on its review, the staff finds the exception to the GALL Report acceptable because the acceptance criteria established by the applicant are more conservative than the acceptance criteria recommended in the GALL Report. Operating Experience. The staff reviewed the operating experience provided in LRA Section B.3.1.2 and also interviewed the applicant's technical staff to confirm that the plant-specific operating experience did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. The staff also confirmed that the applicant has addressed operating experience idehtified after the issuance of the GALL Report. The applicant explained the operating experience of the Concrete Containment Tendon Prestress Program activities. The staff reviewed historic inspection data from basis documents and noted that the most recent prestress tendon inspections were performed in 1999 and 2004. The staff noted that in 1999, forces were determined for 12 tendons (4 vertical, 5 hoop, 3 dome) during the 25 th year surveillance of the reactor building prestressing system and that the 12 tendons constitute a sample of approximately 2% of the total tendon population. The staff noted that the results of the tendon forces were above the 95% of the predicted force at the time of inspection. The staff noted that in 2004, forces were determined for 12 tendons (4 vertical, 5 hoop, 3 dome) during the 30 th year surveillance of the reactor building prestressing system and that the 12 . tendons constitute a sample of approximately 2% of the total tendon population. The staff noted that two tendons (V-137 & V-141) adjacent to tendon V-140 were added to the initial sample and subjected to testing because elongation of tendon V-140, measured during re-tensioning of tendons de-tensioned for removal of sample wires for testing, exceeded the acceptance limit. The staff noted that the elongation of tendon V-140 exceeded the 10% limit, a condition attributed to anchor head rotation observed during the re-tensioning process. And as a result, tendons V-137 and V-141 (like V-140, these tendons curve around the eqUipment opening) were added to the surveillance sample, de-tensioned, and re-tensioned. The staff noted that elongation of the two tendons met the 10% acceptance criterion and elongation of tendon V-140 also met the acceptance criterion during the second retensioning. The staff noted that the applicant's engineering evaluation concluded the initial excess elongation of tendon V-140 was acceptable per ASME IWL-3000. The staff agreed with the applicant's engineering evaluation since it followed the acceptance criteria of ASME IWL-3000. Based on its review, the staff finds that the operating experience of the Concrete Containment Tendon Prestress Program did not show any adverse trend in performance and that any problems identified, would not cause significant impact to the safe operation of the plant. The staff also finds that adequate corrective actions were taken to prevent recurrence and that appropriate guidance 3-125 for re-evaluation, repair, or replacement is provided if degradation is found. The staff noted that periodic self-assessments of the Concrete Containment Tendon Prestress Program are performed to identify the areas that need improvement to maintain the quality performance of the program. The staff concludes that administrative controls are effective in detecting age-related degradation and initiating corrective action. 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 SuDplement. LRA Section A. 3.1.2 provides the UFSAR Supplement for the Concrete Containment Tendon Prestress Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staffs recommended UFSAR Supplement guidance found in the SRP-LR.In LRA Section A.5, Commitment No. 38, the applicant credited the existing program on an ongoing basis.The staff finds that the applicant has provided an adequate summary description of the Concrete Containment Tendon Prestress Program as required by 10 CFR 54.21(d).Conclusion. On the basis of its audit and review of the applicant's Concrete Containment Tendon Prestress Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exception and determined that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. On the basis of its review, the staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and determined that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.3 AMPs That Are Not Consistent with or Not Addressed in the GALL Report In LRA Appendix B, the applicant identified that the Nickel Alloy Aging Management Program is plant-specific. For the AMP that is not consistent with or not addressed by the GALL Report, the staff performed a complete review of the AMP to determine whether it was adequate to monitor or manage aging. The staffs review of this plant-specific AMP is documented in the following section of this SER.3.0.3.3.1 Nickel Alloy Aging Management Program Summary of Technical Information in the Application. LRA Section, Section B.2.2.1 describes the existing Nickel Alloy Aging Management Program as a plant specific program. The applicant states that the program manages cracking caused by primary water stress corrosion cracking (PWSCC) and that inspections, that include volumetric, surface and visual inspection techniques, are implemented through the augmented Inservice Inspection (ISI) program. The applicant further stated that the program provides for component evaluation, repair techniques, and scheduling of inspections in accordance with regulatory, industry, and ASME code requirements and commitments. 3-126 for re-evaluation, repair, or replacement is provided if degradation is found. The staff noted that periodic self-assessments of the Concrete Containment Tendon Prestress Program are performed to identify the areas that need improvement to maintain the quality performance of the program. The staff concludes that administrative controls are effective in detecting age-related degradation and initiating corrective action. The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1 O. The staff finds this program element acceptable. UFSAR Supplement. LRA Section A. 3.1.2 provides the UFSAR Supplement for the Concrete Containment Tendon Prestress Program. The staff confirmed that the applicant's UFSAR Supplement summary description for this program conforms to the staff's recommended UFSAR Supplement guidance found in the SRP-LR. In LRA Section A.5, Commitment No. 38, the applicant credited the existing program on an ongoing basis. The staff finds that the applicant has provided an adequate summary description of the Concrete Containment Tendon Prestress Program as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Concrete Containment Tendon Prestress Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exception and determined that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. On the basis of its review, the staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and determined that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.3 AMPs That Are Not Consistent with or Not Addressed in the GALL Report In LRA Appendix B, the applicant identified that the Nickel Alloy Aging Management Program is plant-specific. For the AMP that is not consistent with or not addressed by the GALL Report, the staff performed a complete review of the AMP to determine whether it was adequate to monitor or manage aging. The staff's review of this plant-specific AMP is documented in the following section of this SER. 3.0.3.3.1 Nickel Alloy Aging Management Program Summary of Technical Information in the Application. LRA Section, Section B.2.2.1 describes the existing Nickel Alloy Aging Management Program as a plant specific program. The applicant states that the program manages cracking caused by primary water stress corrosion cracking (PWSCC) and that inspections, that include volumetric, surface and visual inspection techniques, are implemented through the augmented Inservice Inspection (lSI) program. The applicant further stated that the program provides for component evaluation, repair techniques, and scheduling of inspections in accordance with regulatory, industry, and ASME code requirements and commitments. 3-126 Staff Evaluation. The staff reviewed the Nickel Alloy Aging Management Program against the AMP elements found in the GALL Report, in SRP-LR Section A.1.2.3 and Table A.1-1, focusing on how the program manages aging effects through the effective incorporation of 10 program elements.The staff noted that revisions to 10 CFR 50.55a, "Codes and Standards" were issued in September of 2008 that change the requirements for inspection of nickel alloy welds. The applicant's LRA does not address the new provisions of 10 CFR 50.55a because it was submitted in January 2008.The staff discussed this issue with the applicant on January 15, 2009 who indicated that one of the changes affects this AMP and that the ISI program will be updated accordingly. The applicant indicated that changes have been incorporated into an interim revision of the ISI program and that its scheduling database has been updated to reflect the inspection requirements of ASME Code Case N-722. The applicant further indicated that the changes do not impact the text in the LRA describing the program and that the AMP implements the inspection of components through the augmented ISI program. The applicant indicated that there is no impact to any AMRs as a result of the revision to the regulation. The staff further discussed this issue with the applicant on June 29, 2009 who indicated that the ISI program and the corresponding basis document have been updated based on the revised requirements. Based on its review, the staff finds the applicant's implementation of the provisions of 10 CR 50.55a and ASME Code Case N-722, acceptable. The staff's evaluation of the applicant's program elements is discussed below: Scope of the Program. The "scope of the program" program element in SRP-LR Section A.1.2.3.1 states that the specific program necessary for license renewal should be identified and that the scope of the program should include the specific structures and components of which the program manages the aging.LRA Section B.2.2.1 states that the Nickel Alloy Aging Management Program manages cracking due to primary water stress corrosion cracking for nickel alloy components located in the Steam Generator, Reactor Vessel, Reactor Coolant, and Core Flooding system and that the componentsdo not include steam generator tubes or secondary side components (included in the Steam Generator Tube Integrity Program), reactor vessel internals (included in the PWR Vessel Internals Program), or control rod drive mechanism nozzles (included in the Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program).The staff confirmed that specific systems/components that are subject to the Nickel Alloy Aging Management Program are identified in the LRA including components fabricated with alloy 600 and/or alloy 82/182 weld metal that are located in the Steam Generator, Reactor Vessel, Reactor Coolant, and Core Flooding system.The staff confirmed that the "scope of the program" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1. The staff finds this program element acceptable. Preventive Actions. The "preventive actions" program element in SRP-LR Section A.1.2.3.2 states the following: 3-127 Staff Evaluation. The staff reviewed the Nickel Alloy Aging Management Program against the AMP elements found in the GALL Report, in SRP-LR Section A.1.2.3 and Table A.1-1, focusing on how the program manages aging effects through the effective incorporation of 10 program elements. The staff noted that revisions to 10 CFR 50.55a, "Codes and Standards" were issued in September of 2008 that change the requirements for inspection of nickel alloy welds. The applicant's LRA does not address the new provisions of 10 CFR 50.55a because it was submitted in January 2008. The staff discussed this issue with the applicant on January 15, 2009 who indicated that one of the changes affects this AMP and that the lSI program will be updated accordingly. The applicant indicated that changes have been incorporated into an interim revision of the lSI program and that its scheduling database has been updated to reflect the inspection requirements of ASME Code Case N-722. The applicant further indicated that the changes do not impact the text in the LRA describing the program and that the AMP implements the inspection of components through the augmented lSI program. The applicant indicated that there is no impact to any AMRs as a result of the revision to the regulation. The staff further discussed this issue with the applicant on June 29, 2009 who indicated that the lSI program and the corresponding basis document have been updated based on the revised requirements. Based on its review, the staff finds the applicant's implementation of the provisions of 10 CR 50.55a and ASME Code Case N-722, acceptable. The staffs evaluation of the applicant's program elements is discussed below: Scope of the Program. The "scope of the program" program element in SRP-LR Section A.1.2.3.1 states that the specific program necessary for license renewal should be identified and that the scope of the program should include the specific structures and components of which the program manages the aging. LRA Section B.2.2.1 states that the Nickel Alloy Aging Management Program manages cracking due to primary water stress corrosion cracking for nickel alloy components located in the Steam Generator, Reactor Vessel, Reactor Coolant, and Core Flooding system and that the components do not include steam generator tubes or secondary side components (included in the Steam Generator Tube Integrity Program), reactor vessel internals (included in the PWR Vessel Internals Program), or control rod drive mechanism nozzles (included in the Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program). The staff confirmed that specific systems/components that are subject to the Nickel Alloy Aging Management Program are identified in the LRA including components fabricated with alloy 600 and/or alloy 82/182 weld metal that are located in the Steam Generator, Reactor Vessel, Reactor Coolant, and Core Flooding system. The staff confirmed that the "scope of the program" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.1. The staff finds this program element acceptable. Preventive Actions. The "preventive actions" program element in SRP-LR Section A.1.2.3.2 states the following: 3-127 The activities for prevention and mitigation programs should be described. These actions should mitigate or prevent aging degradation. For condition or performance monitoring programs, they do not rely on preventive actions and thus, this information need not be provided. More than one type of aging management program may be implemented to ensure that aging effects are managed.LRA Section B.2.2.1 states that the Nickel Alloy Aging Management Program includes mitigation activities and strategies to ensure the long-term operability of nickel alloy components. The applicant stated that some of the currently available mitigation techniques include weld overlay, replacement with Alloy 690/52/152 and half nozzle repair. The AMP lists recommended mitigation strategies that are available and considerations to include in a mitigation strategy.The staff confirmed that the Nickel Alloy Aging Management Program is an inspection and repair program that does provide for preventive actions to minimize PWSCC. However, the staff noted that mitigative techniques such as weld overlay repair or half nozzle repair techniques are employed when inspections detect cracking.The staff confirmed that the "preventive actions" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A. 1.2.3.2. The staff finds this program element acceptable. Parameters Monitored/Inspected. The "parameters monitored or inspected" program element in SRP-LR Section A.1.2.3.3 states the following:

  • The parameters to be monitored or inspected should be identified and linked to the degradation of the particular structure and component intended function(s).
  • For a condition monitoring program, the parameter monitored or inspected should detect the presence and extent of aging effects.* For a performance monitoring program, a link should be established between the degradation of the particular structure or component intended function(s) and the parameter(s) being monitored.
  • A performance monitoring program may not ensure the structure and component intended function(s) without linking the degradation of passive intended functions with the performance being monitored.

For prevention and mitigation programs, the parameters monitored should be the specific parameters being controlled to achieve prevention or mitigation of aging effects.LRA Section B.2.2.1 states that the Nickel Alloy Aging Management Program implements the inspection of components through an augmented In-service Inspection (ISI) program. This augmented program administers component evaluations, examination methods, scheduling, and site documentation to comply with regulatory and code requirements or industry commitments related to Nickel Alloy issues. The Nickel Alloy Aging Management Program uses a number of inspection techniques to detect cracking due to PWSCC including surface examinations, volumetric examinations, and bare metal visual examinations. 3-128 The activities for prevention and mitigation programs should be described. These actions should mitigate or prevent aging degradation. For condition or performance monitoring programs, they do not rely on preventive actions and thus, this information need not be provided. More than one type of aging management program may be implemented to ensure that aging effects are managed. LRA Section B.2.2.1 states that the Nickel Alloy Aging Management Program includes mitigation activities and strategies to ensure the long-term operability of nickel alloy components. The applicant stated that some of the currently available mitigation techniques include weld overlay, replacement with Alloy 690/52/152 and half nozzle repair. The AMP lists recommended mitigation strategies that are available and considerations to include in a mitigation strategy. The staff confirmed that the Nickel Alloy Aging Management Program is an inspection and repair program that does provide for preventive actions to minimize PWSCC. However, the staff noted that mitigative techniques such as weld overlay repair or half nozzle repair techniques are employed when inspections detect cracking. The staff confirmed that the "preventive actions" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.2. The staff finds this program element acceptable. Parameters Monitored/Inspected. The "parameters monitored or inspected" program element in SRP-LR Section A.1.2.3.3 states the following:

  • The parameters to be monitored or inspected should be identified and linked to the degradation of the particular structure and component intended function(s).
  • For a condition monitoring program, the parameter monitored or inspected should detect the presence and extent of aging effects.
  • For a performance monitoring program, a link should be established between the degradation of the particular structure or component intended function(s) and the parameter(s) being monitored.
  • A performance monitoring program may not ensure the structure and component intended function(s) without linking the degradation of passive intended functions with the performance being monitored.
  • For prevention and mitigation programs, the parameters monitored should be the specific parameters being controlled to achieve prevention or mitigation of aging effects. LRA Section B.2.2.1 states that the Nickel AlloyAging Management Program implements the inspection of components through an augmented In-service Inspection (lSI) program. This augmented program administers component evaluations, examination methods, scheduling, and site documentation to comply with regulatory and code requirements or industry commitments related to Nickel Alloy issues. The Nickel Alloy Aging Management Program uses a number of inspection techniques to detect cracking due to PWSCC including surface examinations, volumetric examinations, and bare metal visual examinations.

3-128 The staff noted that the parameters to be monitored/inspected that are linked to specific degradation (PWSCC) are identified in the Nickel Alloy Aging Management Program. Cracking is monitored through the augmented ISI program which uses various inspection methods to detect PWSCC depending on the component and long-term operability. Specifically, methods thatmonitor for cracking are visual bare metal inspection, surface inspection and volumetric inspection. Cracking, when discovered by inspection, is mitigated with weld overlay or half nozzle repair techniques. The staff also noted that volumetric, surface, and visual inspections are performed on a periodic basis such that degradation is monitored, but also noted that the Nickel Alloy Aging Management Program is focused on inspection for cracking and repair of any unacceptable cracking.The staff confirmed that the "parameters monitored or inspected" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.3. The staff finds this program element acceptable. Detection of Aging Effects. The "detection of aging effects" program element in SRP-LR Section A. 1.2.3.4 states the following: " Detection of aging effects should occur before there is a loss of the structure and component intended function(s). The parameters to be monitored or inspected should be appropriate to ensure that the structure and component intended function(s) will be adequately maintained for license renewal under all CLB design conditions. This includes aspects such as method or technique (e.g., visual, volumetric, surface inspection), frequency, sample size, data collection and timing of new/one-time inspections to ensure timely detection of aging effects. Provide information that links the parameters to be monitored or inspected to the aging effects being managed." Nuclear power plants are licensed based on redundancy, diversity, and defense-in-depth principles. A degraded or failed component reduces the reliability of the system,challenges safety systems, and contributes to plant risk. Thus, the effects of aging on a structure or component should be managed to ensure its availability to perform its intended function(s) as designed when called upon. In this way, all system level intended function(s), including redundancy, diversity, and defense-in-depth consistent with the plant's CLB, would be maintained for license renewal. A program based solely on detecting structure and component failure should not be considered as an effective aging management program for license renewal." This program element describes "when," "where," and "how" program data are collected (i.e., all aspects of activities to collect data as part of the program).* The method or technique and frequency may be linked to plant-specific or industry-wide operating experience. Provide justification, including codes and standards referenced, thatthe technique and frequency are adequate to detect the aging effects before a loss of SC intended function. A program based solely on detecting SC failures is not considered an effective aging management program.* When sampling is used to inspect a group of SCs, provide the basis for the inspection population and sample size. The inspection population should be based on such aspects of the SCs as a similarity of materials of construction, fabrication, procurement, design, installation, operating environment, or aging effects. The sample size should be based on such aspects of the SCs as the specific aging effect, location, existing technical 3-129 The staff noted that the parameters to be monitored/inspected that are linked to specific degradation (PWSCC) are identified in the Nickel Alloy Aging Management Program. Cracking is monitored through the augmented lSI program which uses various inspection methods to detect PWSCC depending on the component and long-term operability. Specifically, methods that monitor for cracking are visual bare metal inspection, surface inspection and volumetric inspection. Cracking, when discovered by inspection, is mitigated with weld overlay or half nozzle repair techniques. The staff also noted that volumetric, surface, and visual inspections are performed on a periodic basis such that degradation is monitored, but also noted that the Nickel Alloy Aging Management Program is focused on inspection for cracking and repair of any unacceptable cracking. The staff confirmed that the "parameters monitored or inspected" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.3. The staff finds this program element acceptable. Detection of Aging Effects. The "detection of aging effects" program element in SRP-LR Section A.1.2.3.4 states the following:

  • Detection of aging effects should occur before there is a loss of the structure and component intended function(s).

The parameters to be monitored or inspected should be appropriate to ensure that the structure and component intended function( s) will be adequately maintained for license renewal under all CLB design conditions. This includes aspects such as method or technique (e.g., visual, volumetric, surface inspection), frequency, sample size, data collection and timing of new/one-time inspections to ensure timely detection of aging effects. Provide information that links the parameters to be monitored or inspected to the aging effects being managed.

  • Nuclear power plants are licensed based on redundancy, diversity, and defense-in-depth principles.

A degraded or failed component reduces the reliability of the system, challenges safety systems, and contributes to plant risk. Thus, the effects of aging on a structure or component should be managed to ensure its availability to perform its intended function(s) as designed when called upon. In this way, all system level intended function(s), including redundancy, diversity, and defense-in-depth consistent with the plant's CLB, would be maintained for license renewal. A program based solely on detecting structure and component failure should not be considered as an effective aging management program for license renewal.

  • This program element describes "when," "where," and "how" program data are collected (Le., all aspects of activities to collect data as part of the program).
  • The method or technique and frequency may be linked to plant-specific or industry-wide operating experience.

Provide justification, including codes and standards referenced, that the technique and frequency are adequate to detect the aging effects before a loss of SC intended function. A program based solely on detecting SC failures is not considered an effective aging management program.

  • When sampling is used to inspect a group of SCs, provide the basis for the inspection population and sample size. The inspection population should be based on such aspects of the SCs as a similarity of materials of construction, fabrication, procurement, design, installation,operating environment, or aging effects. The sample size should be based on such aspects of the SCs as the specific aging effect, location, existing technical 3-129 information, system and structure design, materials of construction, service environment, or previous failure history. The samples should be biased toward locations most susceptible to the specific aging effect of concern in the period of extended operation.

Provisions should also be included on expanding the sample size when degradation is detected in the initial sample.LRA Section B.2.2.1 states that the Nickel Alloy Aging Management Program uses a number of inspection techniques to detect cracking due to PWSCC including surface examinations, volumetric examinations and bare metal visual examinations. The staff notes that the applicant's Nickel Alloy Aging Management Program is based on the recommendations of NEI and the EPRI Materials Reliability Program (MRP) where components are ranked based on susceptibility in accordance with MRP guidelines. The staff noted that inspection population and sample size are in accordance with MRP guidelines. The staff noted that inspection for PWSCC using appropriate methods for the specific components are performed on a periodic basis such that cracking will be detected before the intended function is compromised. Inspection using volumetric, surface, and visual techniques are performed and scheduled in accordance with the applicant's augmented ISI program. Thefrequency and technique used to detect PWSCC are established in accordance with ASME codes, regulatory requirements, and industry recommendations. The applicant states that inspections will be carried out through the end of the period of extended operation. The staff confirmed that the "detection of aging effects" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A. 1.2.3.4. The staff finds this program element acceptable. Monitoring and Trending. The "monitoring and trending" program element in SRP-LR Section A. 1.2.3.5 states the following: " Monitoring and trending activities should be described, and they should provide predictability of the extent of degradation and thus effect timely corrective or mitigative actions. Plant specific and/or industry-wide operating experience may be considered in evaluating the appropriateness of the technique and frequency.

  • This program element describes "how" the data collected are evaluated and may also include trending for a forward look. This includes an evaluation of the results against the acceptance criteria and a prediction regarding the rate of degradation in order to confirm that timing of the next scheduled inspection will occur before a loss of SC intended function.

Although aging indicators may be quantitative or qualitative, aging indicatorsshould be quantified, to the extent possible, to allow trending. The parameter or indicator trended should be described. The methodology for analyzing the inspection or test results against the acceptance criteria should be described. Trending is a comparison of the current monitoring results with previous monitoring results in order to make predictions for the future.The LRA states that inspection frequencies are in accordance with MRP guidelines and that contingencies for repairs are evaluated prior to each inspection outage. The applicant stated that monitoring of industry-operating experience is performed to incorporate any required changes to 3-130 information, system and structure design, materials of construction, service environment, or previous failure history. The samples should be biased toward locations most susceptible to the specific aging effect of concern in the period of extended operation. Provisions should also be included on expanding the sample size when degradation is detected in the initial sample. LRA Section 6.2.2.1 states that the Nickel Alloy Aging Management Program uses a number of inspection techniques to detect cracking due to PWSCC including surface examinations, volumetric examinations and bare metal visual examinations. The staff notes that the applicant's Nickel Alloy Aging Management Program is based on the recommendations of NEI and the EPRI Materials Reliability Program (MRP) where components are ranked based on susceptibility in accordance with MRP guidelines. The staff noted that inspection population and sample size are in accordance with MRP guidelines. The staff noted that inspection for PWSCC using appropriate methods for the specific components are performed on a periodic basis such that cracking will be detected before the intended function is compromised. Inspection using volumetric, surface, and visual techniques are performed and scheduled in accordance with the applicant's augmented lSI program. The frequency and technique used to detect PWSCC are established in accordance with ASME codes, regulatory requirements, and industry recommendations. The applicant states that inspections will be carried out through the end of the period of extended operation. The staff confirmed that the "detection of aging effects" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.4. The staff finds this program element acceptable. Monitoring and Trending. The "monitoring and trending" program element in SRP-LR Section A.1.2.3.5 states the following:

  • Monitoring and trending activities should be described, and they should provide predictability of the extent of degradation and thus effect timely corrective or mitigative actions. Plant specific and/or industry-wide operating experience may b.e considered in evaluating the appropriateness of the technique and frequency.
  • This program element describes "how" the data collected are evaluated and may also include trending for a forward look. This includes an evaluation of the results against the acceptance criteria and a prediction regarding the rate of degradation in order to confirm that timing of the next scheduled inspection will occur before a loss of SC intended function.

Although aging indicators may be quantitative or qualitative, aging indicators should be quantified, to the extent possible, to allow trending. The parameter or indicator trended should be described. The methodology for analyzing the inspection or test results' against the acceptance criteria should be described. Trending is a comparison of the current monitoring results with previous monitoring results in order to make predictions for the future. The LRA states that inspection frequencies are in accordance with MRP guidelines and that contingencies for repairs are evaluated prior to each inspection outage. The applicant stated that monitoring of industry-operating experience is performed to incorporate any required changes to 3-130 the Nickel Alloy Aging Management Program as a result of industry experience. The applicant further states that inspections are performed as part of an augmented ISI inspection plan where examination results are evaluated according to regulatory requirements and MRP guidance. The applicant states that initiation of an issue report to evaluate the examination results is required when the acceptance criteria is not met.The staff noted that monitoring and trending in the applicant's Nickel Alloy Aging Management Program is performed in accordance with the augmented ISI program which cites ASME code requirements, EPRI MRP guidelines, and regulatory requirements. The staff confirmed that the "monitoring and trending" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.5. The staff finds this program element acceptable. Acceptance Criteria. The "acceptance criteria" program element in SRP-LR Section A.1.2.3.6 states the following:

  • The acceptance criteria of the program and its basis should be described.

The acceptance criteria, against which the need for corrective actions will be evaluated, should ensure that the structure and component intended function(s) are maintained under all CLB design conditions during the period of extended operation. The program should include a methodology for analyzing the results against applicable acceptance criteria.* Acceptance criteria could be specific numerical values, or could consist of a discussion of the process for calculating specific numerical values of conditional acceptance criteria to ensure that the structure and component intended function(s) will be maintained under all CLB design conditions. Information from available references may be cited." It is not necessary to justify any acceptance criteria taken directly from the design basis information that is included in the UFSAR because that is a part of the CLB. Also, it is not necessary to discuss CLB design loads if the acceptance criteria do not permit degradation because a structure and component without degradation should continue to function as originally designed. Acceptance criteria, which do permit degradation, are based on maintaining the intended function under all CLB design loads." Qualitative inspections should be performed to same predetermined criteria as quantitative inspections by personnel in accordance with ASME Code and through approved site specific programs.The LRA states that acceptance criteria are specified in the implementing procedures or work orders in accordance with the applicable regulatory or industry requirements and that any acceptance criteria not currently defined in the UFSAR will be defined by engineering and accepted based on procedures, regulatory requirements and accepted industry practices. The applicant states that all qualitative inspections will be performed to the same predetermined criteria as quantitative inspections in accordance with the ASME code and approved site procedures. The staff noted that acceptance criteria of the Nickel Alloy Aging Management Program are based on ASME code and regulatory requirements and that ASME code methodology are used toanalyze results of any cracking found during volumetric inspection, sizing of weld overlay repair, 3-131 the Nickel Alloy Aging Management Program as a result of industry experience. The applicant further states that inspections are performed as part of an augmented lSI inspection plan where examination results are evaluated according to regulatory requirements and MRP guidance. The applicant states that initiation of an issue report to evaluate the examination results is required when the acceptance criteria is not met. The staff noted that monitoring and trending in the applicant's Nickel Alloy Aging Management Program is performed in accordance with the augmented lSI program which cites ASME code requirements, EPRI MRP guidelines, and regulatory requirements. The staff confirmed that the "monitoring and trending" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.S. The staff finds this program element acceptable. Acceptance Criteria. The "acceptance criteria" program element in SRP-LR Section A.1.2.3.6 states the following:

  • The acceptance criteria of the program and its basis should be described.

The acceptance criteria, against which the need for corrective actions will be evaluated, should ensure that the structure and component intended function(s) are maintained under all CLB design conditions during the period of extended operation. The program should include a methodology for analyzing the results against applicable acceptance criteria.

  • Acceptance criteria could be specific numerical values, or could consist of a discussion of the process for calculating specific numerical values of conditional acceptance criteria to ensure that the structure and component intended function(s) will be maintained under all CLB design conditions.

Information from available references may be cited.

  • It is not necessary to justify any acceptance criteria taken directly from the design basis information that is included in the UFSAR because that is a part of the CLB. Also, it is not necessary to discuss CLB design loads if the acceptance criteria do not permit degradation because a structure and component without degradation should continue to function as originally designed.

Acceptance criteria, which do permit degradation, are based on maintaining the intended function under all CLB design loads.

  • Qualitative inspections should be performed to same predetermined criteria as quantitative inspections by personnel in accordance with ASME Code and through approved site specific programs.

The LRA states that acceptance criteria are specified in the implementing procedures or work orders in accordance with the applicable regulatory or industry requirements and that any acceptance criteria not currently defined in the UFSAR will be defined by engineering and accepted based on procedures, regulatory requirements and accepted industry practices. The applicant states that all qualitative inspections will be performed to the same predetermined criteria as quantitative inspections in accordance with the ASME code and approved site procedures. The staff noted that acceptance criteria of the Nickel Alloy Aging Management Program are based on ASME code and regulatory requirements and that ASME code methodology are used to analyze results of any cracking found during volumetric inspection, sizing of weld overlay repair, 3-131 and the design of half nozzle repair. Additionally, the staff noted that qualitative visual inspections are performed by qualified personnel in accordance with the ASME code and implemented through the applicant's augmented ISI Program.The staff confirmed that the "acceptance criteria" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.6. The staff finds this program element acceptable. Operating Experience. The "operating experience" program element in SRP-LR Section A. 1.2.3.10 states the following: 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.

  • An applicant may have to commit to providing operating experience in the future for new programs to confirm their effectiveness.

The staff reviewed the operating experience described in LRA Section B.2.2.1. The applicant stated that demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that cracking due to PWSCC is being adequately managed.Operating experience provides objective evidence that the Nickel Alloy Aging Management Program will be effective in assuring that intended function(s) will be maintained consistent with the CLB for the period of extended operation. The staff audited the operating experience reports. The staff noted that the Nickel Alloy Aging Management Program provides the details of PWSCC at TMI-1 including past failures and program enhancements as a result of operating experience. The documents reviewed by the staff confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The operating experience provides evidence that PWSCC will be adequately managed 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. LRA Section A.2.2.1 provides the applicant's UFSAR Supplement for the Nickel Alloy Aging Management Program. The staff confirmed that the UFSAR Supplement summary description for the Nickel Alloy Aging Management Program conforms to the staffs recommended UFSAR Supplement for this program as found in the SRP-LR.3-132 and the design of half nozzle repair. Additionally, the staff noted that qualitative visual inspections are performed by qualified personnel in accordance with the ASME code and implemented through the applicant's augmented lSI Program. The staff confirmed that the "acceptance criteria" program element satisfies the criterion defined in the GAll Report and in SRP-lR Section A.1.2.3.6. The staff finds this program element acceptable. Operating Experience. The "operating experience" program element in SRP-lR Section A.1.2.3.10 states the following: .

  • 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.

  • An applicant may have to commit to providing operating experience in the future for new programs to confirm their effectiveness.

The staff reviewed the operating experience described in lRA Section B.2.2.1. The applicant stated that demonstration that the effects of aging are effectively managed is achieved through objective evidence that shows that cracking due to PWSCC is being adequately managed. Operating experience provides objective evidence that the Nickel Alloy Aging Management Program will be effective in assuring that intended function( s) will be maintained consistent with the ClB for the period of extended operation. The staff audited the operating experience reports. The staff noted that the Nickel Alloy Aging Management Program provides the details of PWSCC at TMI-1 including past failures and program enhancements as a result of operating experience. The documents reviewed by the staff confirm that the plant-specific operating experience did not reveal any degradation not bounded by industry experience. The operating experience provides evidence that PWSCC will be adequately managed 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.1.2.3.1

o. The staff finds this program element acceptable.

UFSAR Supplement. LRA Section A.2.2.1 provides the applicant's UFSAR Supplement for the Nickel Alloy Aging Management Program. The staff confirmed that the UFSAR Supplement summary description for the Nickel Alloy Aging Management Program conforms to the staffs recommended UFSAR Supplement for this program as found in the SRP-LR. 3-132 In LRA Section A.5, Commitment No. 35, the applicant credited the existing program and committed to implement applicable Bulletins, Generic Letters, and staff-accepted industry guidelines on an ongoing basis.The staff finds that the applicant has provided an adequate summary description of the Nickel Alloy Aging Management Program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review of the applicant's Nickel Alloy Aging Management Program, the staff concludes that the applicant has demonstrated that the effects of aging will beadequately managed so that the intended function(s) will be maintained during the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs 3.0.4.1 Summary of Technical Information in Application In Appendix A, "Final Safety Analysis Report Supplement," Section A. 1.5, "Quality Assurance Programs and Administrative Controls," and Appendix B, "Aging Management Programs," Section B.1.3, "Quality Assurance Programs and Administrative Controls," of the LRA, the applicant described the "corrective action," "confirmation process," and, "administrative controls" program elements that are applied to the AMPs for both safety-related and nonsafety-related components. The applicant's quality assurance program (QAP) is used which includes the elements of corrective action, confirmation process, and administrative controls which are applied in accordance with the QAP regardless of the safety classification of the components. Section A. 1.5 and Section B.1.3, of the LRA state that the QAP implements the requirements of 10 CFR 50, Appendix B, "Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants," and is consistent with the NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants (SRP-LR)." 3.0.4.2 Staff Evaluation Pursuant to 10 CFR 54.21(a)(3), an applicant is required to demonstrate that the effects of aging on SCs subject to an AMR will be adequately managed so that their intended functions will be maintained consistent with the CLB for the period of extended operation. The SRP-LR, Branch Technical Position RLSB-1, "Aging Management Review -Generic," describes ten attributes of an acceptable AMP. Three of these ten attributes are associated with the QA activities of corrective action, confirmation process, and administrative controls. Table A. 1-1, "Elements of an Aging Management Program for License Renewal," of Branch Technical Position RLSB-1 provides the following description of these quality attributes: Attribute No. 7 -Corrective Actions, including root cause determination and prevention of recurrence, should be timely." Attribute No. 8 -Confirmation Process, which should ensure that preventive actions are adequate and that appropriate corrective actions have been completed and are effective.

  • Attribute No. 9 -Administrative Controls, which should provide a formal review and approval process.3-133 In LRA Section A.5, Commitment No. 35, the applicant credited the existing program and committed to implement applicable Bulletins, Generic Letters, and staff-accepted industry guidelines on an ongoing basis. The staff finds that the applicant has provided an adequate summary description of the Nickel Alloy Aging Management Program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its review of the applicant's Nickel Alloy Aging Management Program, the staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained during the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and concludes that the applicant has provided an adequate summary description of the program, as required by 10 CFR 54.21(d).

3.0.4 Quality

Assurance Program Attributes Integral to Aging Management Programs 3.0.4.1 Summary of Technical Information in Application In Appendix A, "Final Safety Analysis Report Supplement," Section A.1.5, "Quality Assurance Programs and Administrative Controls," and Appendix B, "Aging Management Programs," Section B.1.3, "Quality Assurance Programs and Administrative Controls," of the LRA, the applicant described the "corrective action," "confirmation process," and, "administrative controls" program elements that are applied to the AMPs for both safety-related and nonsafety-related components. The applicant's quality assurance program (QAP) is used which includes the elements of corrective action, confirmation process, and administrative controls which are applied in accordance with the QAP regardless of the safety classification of the components. Section A.1.5 and Section B.1.3, of the LRA state that the QAP implements the requirements of 10 CFR 50, Appendix B, "Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants," and is consistent with the NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants (SRP-LR)." 3.0.4.2 Staff Evaluation Pursuant to 10 CFR 54.21(a)(3), an applicant is required to demonstrate that the effects of aging on SCs subject to an AMR will be adequately managed so that their intended functions will be maintained consistent with the CLB for the period of extended operation. The SRP-LR, Branch Technical Position RLSB-1, "Aging Management Review -Generic," describes ten attributes of an acceptable AMP. Three of these ten attributes are associated with the QA activities of corrective action, confirmation process, and administrative controls. TableA.1-1, "Elements of an Aging Management Program for License Renewal," of Branch Technical Position RLSB-1 provides the following description of these quality attributes: .

  • Attribute No. 7 -Corrective Actions, including root cause determination and prevention of recurrence, should be timely.
  • Attribute NO.8 -Confirmation Process, which should ensure that preventive actions are adequate and that appropriate corrective actions have been completed and are effective.
  • Attribute NO.9 -Administrative Controls, which should provide a formal review and approval process. 3-133 The SRP-LR, Branch Technical Position IQMB-1, "Quality Assurance for Aging Management Programs," states that those aspects of an AMP that affect quality of safety-related structures, systems and. components (SSCs) are subject to the QA requirements of 10 CFR Part 50, Appendix B. Additionally, for nonsafety-related SCs subject to an AMR, the applicant's existing 10 CFR Part 50, Appendix B, QAP may be used to address the elements of corrective action, confirmation process, and administrative control. Branch Technical Position IQMB-1 provides the following guidance with regard to the QA attributes of AMPs: Safety-related SCs are subject to Appendix B to 10 CFR Part 50 requirements which are adequate to address all quality related aspects of an AMP consistent with the CLB of the facility for the period of extended operation.

For nonsafety-related SCs that are subject to an AMR for license renewal, an applicant has an option to expand the scope of its Appendix B to 10 CFR Part 50 program to include these SCs to address corrective action, confirmation process, and administrative control for aging management during the period of extended operation. In this case, the applicant should document such a commitment in the Final Safety Analysis Report supplement in accordance with 10 CFR 54.21(d). The NRC staff reviewed the applicant's AMPs described in Appendix A and Appendix B of the LRA, and the associated implementing documents. The purpose of this review was to ensure that the QA attributes (corrective action, confirmation process, and administrative controls) were consistent with the staff's guidance described in Branch Technical Position IQMB-1.Based on its review, the staff finds that the descriptions of the AMPs and their associated quality attributes provided in Appendix A, Section A.1.5, and Appendix B, Section B.1.3, of the LRA are consistent with the staff's position regarding QA for aging management. 3.0.4.3 Conclusion On the basis of its review, the staff finds that the descriptions and applicability of the plant-specific AMPs and their associated quality attributes provided in Appendix A, Section A.1.5, and Appendix B, Section B. 1.3 of the LRA, are consistent with the staff's position regarding QA for aging management. The staff concludes that the QA attributes (corrective action, confirmation process, and administrative control) of the applicant's AMPs are consistent with 10 CFR 54.21(a)(3). 3-134 The SRP-LR, Branch Technical Position IQMB-1, "Quality Assurance for Aging Management Programs," states that those aspects of an AMP that affect quality of safety-related structures, systems and components (SSCs) are subject to the QA requirements of 10 CFR Part 50, Appendix B. Additionally, for nonsafety-related SCs subject to an AMR, the applicant's existing 10 CFR Part 50, Appendix B, QAP may be used to address the elements of corrective action, confirmation process, and administrative control. Branch Technical Position IQMB-1 provides the following guidance with regard to the QA attributes of AMPs: Safety-related SCs are subject to Appendix B to 10 CFR Part 50 requirements which are adequate to address all quality related aspects of an AMP consistent with the*CLB of the facility for the period of extended operation. For nonsafety-related SCs that are subject to an AMR for license renewal, an applicant has an option to expand the scope of its Appendix B to 10 CFR Part 50 program to include these SCs to address corrective action, confirmation process, and administrative control for aging management during the period of extended operation. In this case, the applicant should document such a commitment in the Final Safety Analysis Report supplement in accordance with 10 CFR 54.21(d). The NRC staff reviewed the applicant's AMPs described in Appendix A and Appendix B of the LRA, and the associated implementing documents. The purpose of this review was to ensure that the QA attributes (corrective action, confirmation process, and administrative controls) were consistent with the staff's guidance described in Branch Technical Position IQMB-1. Based on its.review, the staff finds that the descriptions of the AMPs and their associated quality attributes provided in Appendix A, Section A.1.5, and Appendix B, Section B.1.3, of the LRA are consistent with the staff's position regarding QA for aging management. 3.0.4.3 Conclusion On the basis of its review, the staff finds that the descriptions and applicability of the plant-specific AMPs and their associated quality attributes provided in Appendix A, Section A.1.5, and Appendix B, Section B.1.3 of the LRA, are consistent with the staff's position regarding QA for aging management. The staff concludes that the QA attributes (corrective action, confirmation process, and administrative control) of the applicant's AMPs are consistent with 10 CFR 54.21(a)(3). 3-134

3.1 Aging

Management of Reactor Coolant System This section of the SER documents the staff's review of the applicant's AMR results for the RCS components and component groups of the following: " Reactor Coolant System* Reactor Vessel* Reactor Vessel Internals" Steam Generator

3.1.1 Summary

of Technical Information in the Application LRA Section 3.1 provides AMR results for the reactor coolant system, reactor vessel, reactor vessel internal, and steam generator. LRA Table 3.1.1, "Summary of Aging Management Evaluations for the Reactor Vessel, Internals and Reactor Coolant System," is a summary comparison of the applicant's AMRs with those evaluated in the GALL Report for the reactor coolant system, reactor vessel, reactor vessel internals, and steam generator components and component groups.The applicant's AMRs evaluated and incorporated applicable plant-specific and industry operating experience in the determination of AERMs. The plant-specific evaluation included issue reports and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a review of the GALL Report and operating experience issues identified since the issuance of the GALL Report.3.1.2 Staff Evaluation The staff reviewed LRA Section 3.1 to determine whether the applicant provided sufficient information to demonstrate that the effects of aging for the reactor coolant system, reactor vessel, reactor vessel internals, and steam generator 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 AMPs to ensure the applicant's claim that certain AMPs were consistent with the GALL Report. The purpose of this audit was to examine the applicant's AMPs and related documentation and to verify the applicant's claim of consistency with the corresponding GALL Report AMPs. The staff did not repeat its review of the matters described in the GALL Report. The staff's evaluations of the AMPs are documented in SER Section 3.0.3.The staff reviewed the AMRs to confirm the applicant's claim that certain identified AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant had identified the appropriate GALL Report AMRs. Details of the staff's evaluation are discussed in SER Section 3.1.2.1 and 3.1.2.2.The staff also reviewed the AMRs not consistent with or not addressed in the GALL Report. The review evaluated whether all plausible aging effects were identified and whether the aging effects 3-135 3.1 Aging Management of Reactor Coolant System This section of the SER documents the staffs review of the applicant's AMR results for the RCS components and component groups of the following:

  • Reactor Coolant System
  • Reactor Vessel
  • Reactor Vessel Internals
  • Steam Generator

3.1.1 Summary

of Technical Information in the Application LRA Section 3.1 provides AMR results for the reactor coolant system, reactor vessel, reactor vessel internal, and steam generator. LRA Table 3.1.1, "Summary of Aging Management Evaluations for the Reactor Vessel, Internals and Reactor Coolant System," is a comparison of the applicant's AMRs with those evaluated in the GALL Report for the reactor coolant syste'm, reactor vessel, reactor vessel internals, and steam generator components and component groups. The applicant's AMRs evaluated and incorporated applicable plant-specific and industry operating experience in the determination of AERMs. The plant-specific evaluation included issue reports and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a review of the GALL Report and operating experience issues identified since the issuance of the GALL Report. 3.1.2 Staff Evaluation The staff reviewed LRA Section 3.1 to determine whether the applicant provided sufficient information to demonstrate that the effects of aging for the reactor coolant system, reactor vessel, reactor vessel internals, and steam generator 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 AMPs to ensure the applicant's claim that certain AM"Ps were consistent with the GALL Report. The purpose of this audit was to examine the applicant's AMPs and related documentation and to verify the applicant's claim of conSistency with the corresponding GALL Report AMPs. The staff did not repeat its review of the matters described in the GALL Report. The staff's evaluations of the AMPs are documented in SER Section 3.0.3. The staff reviewed the AMRs to confirm the applicant's claim that certain identified AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant had identified the appropriate GALL Report AMRs. Details of the staffs evaluation are discussed in SER Section 3.1.2.1 and 3.1.2.2. The staff also reviewed the AMRs not consistent with or not addressed in the GALL Report. The review whether all plausible aging effects were identified and whether the aging effects '"".':;': 3-135 listed were appropriate for the combination of materials and environments specified. Details of the staff's evaluation are discussed 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 plant's operating experience to verify the applicant's claims.Table 3.1-1 summarizes the staff's evaluation of components, aging effects or mechanisms, and AMPs listed in LRA Section 3.1 and addressed in the GALL Report.Table 3.1-1 Staff Evaluation for Reactor Vessel, Reactor Vessel Internals, and Reactor Coolant System Components in the GALL Report Component Group Aging.Effectl, "AM L-GALL Further. .P... in ..... 'Sta.(GALL Report.Item No.) Mechanism Ea.uRetro n supplements., Eva uation (GALL Report-"e"ort -in7GALL or__________ Re port" Steel pressure vessel Cumulative TLAA, evaluated in Yes TLAA Fatigue is a support skirt and fatigue damage accordance with TLAA (See attachment welds 10 CFR 54.21(c) SER Section (3.1.1-1) 3.1.2.2.1) Steel; stainless steel; steel Cumulative TLAA, evaiuated in Yes Not applicable Not applicable with nickel-alloy or fatigue damage accordance with to PWRs (See stainless steel cladding; 10 CFR 54.21(c) and Section nickel-alloy reactor vessel environmental effects 3.1.2.2.1) components: flanges; are to be addressed nozzles; penetrations; for Class 1 safe ends; thermal components sleeves; vessel shells, heads and welds (3.1.1-2)Steel; stainless steel; steel Cumulative TLAA, evaluated in Yes Not applicable Not applicable with nickel-alloy or fatigue damage accordance with to PWRs (See stainless steel cladding; 10 CFR 54.21(c) and Section nickel-alloy reactor coolant environmental effects 3.1.2.2.1) pressure boundary piping, are to be addressed piping components, and for Class 1 piping elements exposed components to reactor coolant (3.1.1-3)Steel pump and valve Cumulative TLAA, evaluated in Yes Not applicable Not applicable closure bolting fatigue damage accordance with to PWRs (See (3.1.1-4) 10 CFR 54.21(c) Section check Code limits for 3.1.2.2.1) allowable cycles (less than 7000 cycles) of thermal stress range Stainless steel and nickel Cumulative TLAA, evaluated in Yes TLAA Fatigue is a alloy reactor vessel fatigue damage accordance with TLAA (See internals components 10 CFR 54.21(c) SER Section (3.1.1-5) 3.1.2.2.1) 3-136 listed were appropriate for the combination of materials and environments specified. Details of the staff's evaluation are discussed 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 plant's operating experience to verify the applicant's claims. Table 3.1-1 summarizes the staff's evaluation of components, aging effects or mechanisms, and AMPs listed in LRA Section 3.1 and addressed in the GALL Report. Table 3.1-1 Staff Evaluation for Reactor Vessel, Reactor Vessel Internals, and Reactor Coolant System Components in the GALL Report ' ,.: .. , " .': :t',':':::** ,.,' I;;:'\':,y#":':,,'," Steel pressure vessel support skirt and attachment welds (3.1.1-1) Cumulative fatigue damage Steel; stainless steel; steel Cumulative with nickel-alloy or fatigue damage stainless steel cladding; nickel-alloy reactor vessel components: flanges; nozzles; penetrations; safe ends; thermal sleeves; vessel shells, heads and welds (3.1.1-2) Steel; stainless steel; steel Cumulative , with nickel-alloy or fatigue damage stainless steel cladding; nickel-alloy reactor coolant pressure boundary piping, piping components, and piping elements exposed to reactor coolant (3.1.1-3) Steel pump and valve Cumulative closure bolting fatigue damage (3.1.1-4) Stainless steel and nickel Cumulative alloy reactor vessel fatigue damage internals components (3.1.1-5) TLAA, evaluated in accordance with 10 CFR 54.21 (c) Yes TLAA, evaiuated in Yes accordance with 10 CFR 54.21(c) and environmental effects are to be addressed for Class 1 components TLAA, evaluated in Yes accordance with 10 CFR 54.21(c) and environmental effects are to be addressed for Class 1 components TLAA, evaluated in accordance with 10 CFR 54.21(c) check Code limits for allowable cycles (less than 7000 cycles) of thermal stress range TLAA, evaluated in accordance with 10 CFR 54.21(c) 3-136 Yes Yes TLAA Fatigue is a TLAA(See SER Section 3.1.2.2.1 ) Not applicable Not applicable Not applicable to PWRs (See Section 3.1.2.2.1) Not applicable to PWRs (See Section 3.1.2.2.1 ) Not applicable Not applicable to PWRs (See Section 3.1.2.2.1 ) TLAA Fatigue is a TLAA(See SER Section 3.1.2.2.1 ) Coroet Gru Ag ing, Effectl AMVP in GA-LL Further 'AMP in LRA, !;Staff:: (GALLRep~lt Itrem No.)' Meanitsm' 'i tReort Evaluatio'n Evaluation inGALIL or Report._. Amendments Nickel Alloy tubes and Cumulative TLAA, evaluated in Yes TLAA Fatigue is a sleeves in a reactor fatigue damage accordance with TLAA (See coolant and secondary 10 CFR 54.21(c) SER Section feedwater/steam 3.1.2.2.1) environment (3.1.1-6)Steel and stainless steel Cumulative TLAA, evaluated in Yes TLAA Fatigue is a reactor coolant pressure fatigue damage accordance with TLAA (See boundary closure bolting, 10 CFR 54.21(c) SER Section head closure studs, 3.1.2.2.1) support skirts and attachment welds, pressurizer relief tank components, steam generator components, piping and components external surfaces and bolting (3.1.1-7)Steel; stainless steel; and Cumulative TLAA, evaluated in Yes TLAA Fatigue is a nickel-alloy reactor coolant fatigue damage accordance with TLAA (See pressure boundary piping, 10 CFR 54.21(c) and SER Section piping components, piping environmental effects 3.1.2.2.1) elements; flanges; nozzles are to be addressed and safe ends; pressurizer for Class 1 vessel shell heads and components welds; heater sheaths and sleeves; penetrations; and thermal sleeves (3.1.1-8)Steel; stainless steel; steel Cumulative TLAA, evaluated in Yes TLAA Fatigue is a with nickel-alloy or fatigue damage accordance with TLAA (See stainless steel cladding; 10 CFR 54.21(c) and SER Section nickel-alloy reactor vessel environmental effects 3.1.2.2.1) components: flanges; are to be addressed nozzles; penetrations; for Class 1 pressure housings; safe components ends; thermal sleeves;vessel shells, heads and welds (3.1.1-9)Steel; stainless steel; steel Cumulative TLAA, evaluated in Yes TLAA Fatigue is a with nickel-alloy or fatigue damage accordance with TLAA (See stainless steel cladding; 10 CFR 54.21(c) and SER Section nickel-alloy steam environmental effects 3.1.2.2.1) generator components are to be addressed (flanges; penetrations; for Class 1 nozzles; safe ends, lower components heads and welds)(3.1.1-10) 3-137 Nickel Alloy tubes and sleeves in a reactor coolant and secondary feedwaterlsteam environment (3.1.1-6) Steel and stainless steel reactor coolant pressure boundary closure bolting, head closure studs, support skirts and attachment welds, pressurizer relief tank components, steam generator components, piping and components extemal surfaces and bolting (3.1.1-7) Cumulative fatigue damage Cumulative fatigue damage Steel; stainless steel; and Cumulative nickel-alloy reactor coolant fatigue damage 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) 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) 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 Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) TLAA, evaluated in accordance with 10 CFR 54.21(c) Yes Yes TLAA, evaluated in Yes accordance with 10 CFR 54.21 (c) and environmental effects are to be addressed for Class 1 components TLAA, evaluated in Yes accordance with 10 CFR 54.21(c) and environmental effects are to be addressed for Class 1 components TLAA, evaluated in Yes accordance with 10 CFR 54.21(c) and environmental effects are to be addressed for Class 1 components 3-137 TLAA TLAA TLAA TLAA TLAA Fatigue is a TLAA(See SER Section 3.1.2.2.1 ) Fatigue is a TLAA(See SER Section 3.1.2.2.1 ) . Fatigue is a TLAA(See SER Section 3.1.2.2.1 ) Fatigue is a TLAA (See SER Section 3.1.2.2.1 ) Fatigue is a TLAA(See SER Section 3.1.2.2.1 ) ,Component Group .:gig ffectI: AMP in GALL F e AMP in LRA, Staff:~::: ,r -'ý,; .--{(GAL Reprt Iem'N.) M~ha Evaluation Supp'lemenits Evaluationý(GLLR~or lem~No), Mehnism.' Report' i0GLLo Report Amendmerntsl Steel top head enclosure Loss of material Water Chemistry and Yes Not applicable Not applicable (without cladding) top due to general, One-Time Inspection to PWRs (See head nozzles (vent, top pitting and Section head spray or RCIC, and crevice 3.1.2.2.2) spare) exposed to reactor corrosion coolant (3.1.1-11) Steel steam generator Loss of material Water Chemistry and Yes Water Chemistry Consistent with shell assembly exposed to due to general, One-Time Inspection One-Time GALL Report secondary feedwater and pitting and Inspection (See SER steam crevice Section (3.1.1-12) corrosion 3.1.2.2.2) Steel and stainless steel Loss of material Water Chemistry and Yes Not applicable Not applicable isolation condenser due to general One-Time Inspection to PWRs (See components exposed to (steel only), Section reactor coolant pitting and 3.1.2.2.2) (3.1.1-13) crevice corrosion Stainless steel, nickel- Loss of material Water Chemistry and Yes Not applicable Not applicable alloy, and steel with due to pitting One-Time Inspection to PWRs (See nickel-alloy or stainless and crevice Section steel cladding reactor corrosion 3.1.2.2.2) vessel flanges, nozzles, penetrations, safe ends, vessel shells, heads and welds (3.1.1-14) Stainless steel; steel with Loss of material Water Chemistry and Yes Not applicable Not applicable nickel-alloy or stainless due to pitting One-Time Inspection to PWRs (See steel cladding; and nickel- and crevice Section alloy reactor coolant corrosion 3.1.2.2.2) pressure boundary components exposed to reactor coolant (3.1.1-15)Steel steam generator Loss of material Inservice Yes Not applicable Not applicable upper and lower shell and due to general, Inspection (IWB, to TMI-1. (See transition cone exposed to pitting and IWC, and IWD), and SER Section secondary feedwater and crevice Water Chemistry 3.1.2.2.2) steam corrosion and, for (3.1.1-16) 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. 3-138 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 ) Steel steam generator shell assembly exposed to secondary feedwater and steam (3.1.1-12) Steel and stainless steel isolation condenser components exposed to reactor coolant (3.1.1-13) 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) 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) 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 Water Chemistry and Yes One-Time Inspection Loss of material Water Chemistry and Yes due to general, One-Time Inspection pitting and crevice corrosion Loss of material Water Chemistry and Yes due to general One-Time Inspection (steel only), pitting and crevice corrosion Loss of material Water Chemistry and Yes due to pitting One-Time Inspection and crevice corrosion Loss of material Water Chemistry and Yes due to pitting One-Time Inspection and crevice corrosion Loss of material In service Yes due to general, Inspection (IW8, pitting and IWC, and IWD), and crevice Water Chemistry corrosion 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. 3-138 Not applicable Not applicable to PWRs (See Section 3.1.2.2.2) Water Chemistry Consistent with One-Time GALL Report Inspection (See SER Section 3.1.2.2.2) Not applicable Not applicable to PWRs (See Section 3.1.2.2.2) Not applicable Not applicable to PWRs (See Section 3.1.2.2.2) Not applicable Not applicable to PWRs (See Section 3.1.2.2.2) Not applicable Not applicable to TMI-1. (See SER Section 3.1.2.2.2) comporiet GroGup Aging Effectit , !AMPi n GALL Further, AMP in RA, s;taff s eLLn irr a ni sm" RendiEvaluationx Supplemaents, Eval ation, (.1.Rote Mebittemnt RG1..Theport 3..2in GALL or, Report Amenments, Steel (with or without Loss of fracture TLAA, evaluated in Yes TLAA Loss of fracture stainless steel cladding) toughness due accordance with toughness is a reactor vessel beftline to neutron 10 CFR 50, TLAA (See shell, nozzles, and welds irradiation Appendix G, and SER Section (3.1.1-17) embrittlement RG 1.99. The 3.1.2.2.3) applicant may choose to demonstrate that the materials of the nozzles are not controlling for the TLAA evaluations. Steel (with or without Loss of fracture Reactor Vessel Yes Reactor Vessel Consistent with stainless steel cladding) toughness due Surveillance Surveillance GALL Report reactor vessel beltline to neutron (See SER shell, nozzles, and welds; irradiation Section safety injection nozzles embrittlement 3.1.2.2.3) (3.1.1-18) Stainless steel and nickel Cracking due to A plant-specific aging Yes Not applicable Not applicable alloy top head enclosure stress corrosion management to PWRs (See vessel flange leak cracking and program is to be SER Section detection line intergranular evaluated. 3.1.2.2.4) (3.1.1-19) stress corrosion cracking Stainless steel isolation Cracking due to Inservice Yes Not applicable Not applicable condenser components stress corrosion Inspection (IWB, to PWRs (See exposed to reactor coolant cracking and IWC, and IWD), SER Section (3.1.1-20) intergranular Water Chemistry, 3.1.2.2.4) stress corrosion and plant-specific cracking verification program Reactor vessel shell Crack growth TLAA Yes TLAA Crack growthfabricated of SA508-Cl 2 due to cyclic due to cyclic forgings clad with loading loading is a stainless steel using a TLAA. (See high-heat-input welding SER Section process 3.1.2.2.5) (3.1.1-21) Stainless steel and nickel Loss of fracture UFSAR Supplement Yes UFSAR Consistent with alloy reactor vessel toughness due commitment to Supplement GALL Report internals components to neutron (1) participate in Section A.5, (See SER exposed to reactor coolant irradiation industry RVI aging Commitment Section and neutron flux embrittlement, programs Number 36 3.1.2.2.6) (3.1.1-22) void swelling (2) implement applicable results (3)submit for NRC approval > 24 months before the extended period an RVI inspection plan based on industry recommendation. 3-139 Steel (with or without stainless steel cladding) reactor vessel beltline shell. nozzles. and welds (3.1.1-17) Steel (with or without stainless steel cladding) reactor vessel beltline shell. nozzles. and welds; safety injection nozzles (3.1.1-18) Stainless steel and nickel alloy top head enclosure vessel flange leak detection line (3.1.1-19) Loss of fracture toughness due to neutron irradiation embrittlement Loss of fracture toughness due to neutron irradiation embrittlement Cracking due to stress corrosion cracking and intergranular stress corrosion cracking Stainless steel isolation Cracking due to condenser components stress corrosion exposed to reactor coolant cracking and (3.1.1-20) intergranular Reactor vessel shell fabricated of SA508-CI 2 forgings clad with stainless steel using a high-heat-input welding process (3.1.1-21 ) stress corrosion cracking Crack growth due to cyclic loading Stainless steel and nickel Loss of fracture alloy reactor vessel toughness due internals components to neutron exposed to reactor coolant irradiation and neutron flux embrittlement. (3.1.1-22) void swelling TLAA. evaluated in Yes 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. Reactor Vessel Surveillance Yes A plant-specific aging Yes management program is to be evaluated. Inservice Inspection (IWB. IWC. and IWD). Water Chemistry. and plant-specific verification program TLAA Yes Yes UFSAR Supplement Yes 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. 3-139 TLAA Reactor Vessel Surveillance Not applicable Not applicable TLAA UFSAR Supplement Section A.5. Commitment* Number 36 Loss of fracture toughness is a TLAA(See SER Section 3.1.2.2.3) Consistent with GALL Report (See SER Section 3.1.2.2.3) Not applicable to PWRs (See SER Section 3.1.2.2.4) Not applicable to PWRs (See SER Section 3.1.2.2.4) Crack growth due to cyclic loading is a TLAA. (See SER Section 3.1.2.2.5) Consistent with GALL Report (See SER Section 3.1.2.2.6) Component Grou Aging Effect/ AMP ,in'.GALL Further .AMVP inLRA, k Staff M Evaluatio Supplem'ents, Evaluation (GALLkR6oit Item -No.) Meca-ii" pO Eivaidmtio -Sypp~em Reot .i~n GALL 7 or______________ __________?rt Amendments Stainless steel reactor Cracking due to A plant-specific aging Yes Water Chemistry Consistent with vessel closure head flange stress corrosion management Inservice GALL Report leak detection line and cracking program is to be Inspection, (See SER bottom-mounted evaluated. Subsections Section instrument guide tubes IWB, IWC, and 3.1.2.2.7) (3.1.1-23) IWD Class I cast austenitic Cracking due to Water Chemistry Yes Not applicable Not applicable stainless steel piping, stress corrosion and, for CASS to TMI-1. (See piping components, and cracking components that do SER Section piping elements exposed not meet the 3.1.2.2.7) to reactor coolant NUREG-0313 (3.1.1-24) guidelines, a plant specific AMPStainless steel jet pump. Cracking due to A plant-specific aging Yes Not applicable Not applicable sensing line cyclic loading management to PWRs (See (3.1.1-25) program is to be SER Section evaluated. 3.1.2.2.8) Steel and stainless steel Cracking due to Inservice Yes Not applicable Not applicable isolation condenser cyclic loading Inspection (IWB, to PWRs (See components exposed to IWC, and IWD) and SER Sectionreactor coolant plant-specific 3.1.2.2.8) (3.1.1-26) verification programStainless steel and nickel Loss of preload UFSAR Supplement Yes UFSAR Consistent with alloy reactor vessel due to stress commitment to Supplement GALL Report internals screws, bolts, tie relaxation (1) participate in Section A.5, (See SER rods, and hold-down industry RVI aging Commitment Section springs programs Number 36 3.1.2.2.9) (3.1.1-27) (2) implementapplicable results (3)submit for NRC approval > 24 months before the extended period an RVI inspection plan based on industry recommendation. Steel steam generator Loss of material A plant-specific aging Yes Not applicable Not applicable feedwater impingement due to erosion management to TMI-1. (See plate and support exposed program is to be SER Section to secondary feedwater evaluated. 3.1.2.2.10) (3.1.1-28)Stainless steel steam Cracking due to A plant-specific aging Yes Not applicable Not applicable dryers exposed to reactor flow-induced management to PWRs (See coolant vibration program is to be SER Section (3.1.1-29) evaluated. _3.1.2.2.11) 3-140 Stainless steel reactor Cracking due to vessel closure head flange stress corrosion leak detection line and cracking bottom-mounted instrument guide tubes (3.1.1-23) Class 1 cast austenitic Cracking due to stainless steel piping, stress corrosion piping components, and cracking piping elements exposed to reactor coolant (3.1.1-24) Stainless steel jet pump Cracking due to sensing line cyclic loading (3.1.1-25) Steel and stainless steel Cracking due to isolation condenser cyclic loading components exposed to reactor coolant (3.1.1-26) Stainless steel and nickel Loss of preload alloy reactor vessel due to stress intemals screws, bolts, tie relaxation rods, and hold-down springs (3.1.1-27) Steel steam generator Loss of material feedwater impingement due to erosion plate and support exposed to secondary feedwater (3.1.1-28) Stainless steel steam Cracking due to dryers exposed to reactor flow-induced coolant vibration (3.1.1-29) A plant-specific aging management program is to be evaluated. Water Chemistry and, for CASS components that do not meet the NUREG-0313 guidelines, a plant specific AMP A plant-specific aging management program is to be evaluated. In service Inspection (IWB, IWC, and IWD) and plant-specific verification program UFSAR Supplement commitment to (1) participate in industry RVI aging programs (2) implement applicable results (3) submit for NRC approval> 24 months before the extended period an RVI inspection plan based on industry recommendation. A plant-specific aging management program is to be evaluated. A plant-specific aging management

program is to be evaluated. 3-140 Yes Yes Yes Yes Yes Yes Yes Water Chemistry Consistent with Inservice GALL Report Inspection, (See SER Subsections Section IWB,IWC, and 3.1.2.2.7) IWD Not applicable Not applicable Not applicable UFSAR Supplement Section A.5, Commitment Number 36 Not applicable Not applicable Not applicable to TMI-1. (See SER Section 3.1.2.2.7) Not applicable to PWRs (See SER Section 3.1.2.2.8) Not applicable to PWRs (See SER Section 3.1.2.2.8) Consistent with GALL Report (See SER Section 3.1.2.2.9) Not applicable to TMI-1. (See SER Section 3.1.2.2.10) Not applicable to PWRs (See SER Section 3.1.2.2.11) Component Groupr Aging Efferttr AMP, in GALL- Futh AMP in LRAI Staff (GALL Report Item No.), Mechanism Report-- Evaluation Sulements, Evauation r in.ALL -or__________________ Mechanism ., pReport Amendments Stainless steel reactor Cracking due to Water Chemistry and Yes Water Chemistry Consistent with vessel internals stress corrosion UFSAR Supplement UFSAR GALL Report components (e.g., Upper cracking, commitment to Supplement (See SER internals assembly, RCCA irradiation-(1) participate in Section A.5, Section guide tube assemblies, assisted stress industry RVI aging Commitment 3.1.2.2.12) Baffle/former assembly, corrosion programs Number 36 Lower internal assembly, cracking (2) implement shroud assemblies, applicable results Plenum cover and plenum (3) submit for NRC cylinder, Upper grid approval > 24 assembly, Control rod months before the guide tube (CRGT) extended period an assembly, Core support RVI inspection plan shield assembly, Core based on industry barrel assembly, Lower recommendation. grid assembly, Flow distributor assembly, Thermal shield, Instrumentation support structures) (3.1.1-30) Nickel alloy and steel with Cracking due to Inservice Yes Inservice Consistent with nickel-alloy cladding primary water Inspection (IWB, Inspection, GALL Report piping, piping component, stress corrosion IWC, and IWD) and Subsections (See SER piping elements, cracking Water Chemistry and IWB, IWC, and Section penetrations, nozzles, UFSAR Supplement IWD 3.1.2.2.13)safe ends, and welds commitment to Water Chemistry (other than reactor vessel implement applicable head); pressurizer heater plant commitments to For nickel alloy, sheaths, sleeves, (1) NRC Orders, compliance with diaphragm plate, Bulletins, and NRC Orders and manways and flanges; Generic Letters UFSAR core support pads/core associated with Supplement guide lugs nickel alloys and Section A.5, (3.1.1-31) (2) staff-accepted Commitment industry guidelines. Number 35 Steel steam generator Wall thinning A plant-specific aging Yes Not applicable Applies only to feedwater inlet ring and due to flow- management Recirculating supports accelerated program is to be Steam (3.1.1-32) corrosion evaluated. Generators. TMI-1 has Once-Through Steam Generators.(See SER Section.3.1.2.2.14) 3-141 I',,' ..... - Effectt ::' ,.-' , .* .* ' '" Stainless steel reactor Cracking due to vessel internals stress corrosion components (e.g., Upper cracking, internals assembly, RCCA irradiation-guide tube assemblies, assisted stress Baffle/former assembly, corrosion Lower internal assembly, cracking 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) Nickel alloy and steel with Cracking due to nickel-alloy cladding primary water piping, piping component, stress corrosion piping elements, cracking 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 ) Steel steam generator Wall thinning feedwater inlet ring and due to f1ow-supports accelerated (3.1.1-32) corrosion Water Chemistry and UFSAR Supplement commitment to (1) participate in industry RVI aging programs (2) implement applicable results (3) submit for NRC approval> 24 months before the extended period an RVI inspection plan based on industry recommendation. Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry and UFSAR Supplement commitment to implement applicable plant commitments to (1) NRC Orders, Bulletins,and Generic Letters associated with nickel alloys and (2) staff-accepted industry guidelines. A plant-specific aging management program is to be evaluated. 3-141 Yes, Yes Yes Water Chemistry Consistent with UFSAR GALL Report Supplement (See SER Section A.5, Section Commitment 3.1.2.2.12) Number 36 Inservice Consistent with Inspection, GALL Report . Subsections (See SER IWB, IWC, and Section IWD 3.1.2.2.13) Water Chemistry For nickel alloy, compliance with NRC Orders and UFSAR Supplement Section A.5, Commitment Number 35 Not applicable Applies only to Recirculating Steam Generators. TMI-1 has Once-Through Steam Generators. (See SER Section 3.1.2.2.14) Comipon'ent'Group' Agin~g Efc/ AMP in GALL Furhe 7AMP in LKR, Staff-'(GALL Report Item No.) Mechanism, Report Evaluation Supplements, Evaluation.

  • i~nGALL r_________Report~

Amen6dments, Stainless steel and nickel Changes in UFSAR Supplement Yes UFSAR Consistent with alloy reactor vessel dimensions due commitment to Supplement GALL Report internals components to void swelling (1) participate in Section A.5, (See SER (3.1.1-33) industry RVI aging Commitment Section programs Number 36 3.1.2.2.15) (2) implement applicable results (3) submit for NRC approval > 24 months before the extended period an RVI inspection plan based on industry recommendation. Stainless steel and nickel Cracking due to Inservice Yes Inservice Consistent with alloy reactor control rod stress corrosion Inspection (IWB, Inspection,. GALL Report drive head penetration cracking and IWC, and IWD) and Subsections (See SER pressure housings primary water Water Chemistry and IWB, IWC, and Section (3.1.1-34) stress corrosion for nickel alloy, IWD 3.1.2.2.16) cracking comply with Water Chemistry applicable NRCOrders and provide a For nickel alloy, commitment in the compliance with UFSAR Supplement NRC Orders and to implement UFSAR applicable Supplement (1) Bulletins and Section A.5, Generic Letters and Commitment (2) staff-accepted Number 35 industry guidelines. Steel with stainless steel Cracking due to Inservice Yes Inservice Consistent with or nickel alloy cladding stress corrosion Inspection (IWB, Inspection, GALL Report primary side components; cracking and IWC, and IWD) and Subsections (See SER steam generator upper primary water Water Chemistry and IWB, IWC, and Section and lower heads, stress corrosion for nickel alloy, IWD 3.1.2.2.16) tubesheets and tube-to- cracking comply with Water Chemistry tube sheet welds applicable NRC (3.1.1-35). Orders and provide a For nickel alloy, commitment in the compliance with UFSAR Supplement NRC Orders and to implement UFSAR applicable Supplement, (1) Bulletins and Section A.5, Generic Letters and Commitment (2) staff-accepted Number 35 industry guidelines. 3-142 Stainless steel and nickel alloy reactor vessel intemals components (3.1.1-33) Stainless steel and nickel alloy reactor control rod drive head penetration pressure housings . (3.1.1-34) Steel with stainless steel or nickel alloy cladding primary side components; steam generator upper and lower heads, tubesheets and tube-to-tube sheet welds (3.1.1-35) Changes in dimensions due to void swelling Cracking due to stress corrosion cracking and primary water stress corrosion cracking Cracking due to stress corrosion cracking and primary water stress corrosion cracking UFSAR Supplement Yes 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. Inservice Inspection (IWB, IWC, and IWO) and Water Chemistry and for nickel alloy, comply with applicable NRC Orders and provide a commitment in the UFSAR Supplement to implement applicable (1) Bulletins and Generic Letters and (2) staff-accepted industry guidelines. Inservice

Inspection (IWB, IWC, and IWO) and Water Chemistry and for nickel alloy, comply with applicable NRC Orders and provide a commitment in the UFSAR Supplement to implement applicable (1) Bulletins and Generic Letters and (2) staff-accepted industry guidelines. 3-142 Yes Yes UFSAR Supplement Section A.5, Commitment Number 36 In service Inspection, . Subsections IWB, IWC, and IWO Water Chemistry For nickel alloy, compliance with NRC Orders and UFSAR Supplement Section A.5, Commitment Number 35 Inservice Inspection, Subsections IWB, IWC, and IWO Water Chemistry For nickel alloy, compliance with NRC Orders and UFSAR Supplement, Section A.5, Commitment Number 35 Consistent with GALL Report (See SER Section 3.1.2.2.15) Consistent with GALL Report (See SER Section 3.1.2.2.16) Consistent with GALL Report (See SER Section 3.1.2.2.16) Component Group'. -Aging Efct AMP-in GALL Further AMP in.LRA, Staff.(GALL Report Item -No.) Mechanism Report .Evaluationi. Suppliiemts, Evaluation in GALL .or-, ~ ~ ~ .~Report. Amn ets,-Nickel alloy, stainless steel Cracking due to Water Chemistry and Yes Not applicable Not applicablepressurizer spray head stress corrosion One-Time Inspection to TMI-1 (See (3.1.1-36) cracking and and, for nickel alloy SER Section primary water welded spray heads, 3.1.2.2.16) stress corrosion comply with cracking applicable NRC Orders and provide a commitment in the UFSAR Supplementto implement applicable (1) Bulletins and Generic Letters and (2) staff-accepted industry guidelines. Stainless steel and nickel Cracking due to Water Chemistry and Yes Water Chemistry Consistent with alloy reactor vessel stress corrosion UFSAR Supplement UFSAR GALL Report internals components cracking, commitment to Supplement (See SER (e.g., Upper intemals primary water (1) participate in Section A.5, Section assembly, RCCA guide stress corrosion industry RVI aging Commitment 3.1.2.2.17) tube assemblies, Lower cracking, programs Number 36 internal assembly, CEA irradiation-(2) implement shroud assemblies, Core assisted stress applicable results shroud assembly, Core corrosion (3) submit for NRC support shield assembly, cracking approval > 24 Core barrel assembly, months before the Lower grid assembly, Flow extended period an distributor assembly) RVI inspection plan (3.1.1-37) based on industry recommendation. Steel (with or without Cracking due to BWR Control Rod No Not applicable Not applicable stainless steel cladding) cyclic loading Drive Return Line to PWRs control rod drive return Nozzle line nozzles exposed to reactor coolant (3.1.1-38) Steel (with or without Cracking due to BWR Feedwater No Not applicable Not applicable stainless steel cladding) cyclic loading Nozzle to PWRs feedwater nozzles exposed to reactor coolant (3.1.1-39) Stainless steel and nickel Cracking due to BWR Penetrations No Not applicable Not applicable alloy penetrations for stress corrosion and Water Chemistry to PWRs control rod drive stub cracking, tubes instrumentation, jet Intergranular pump instrumentation, stress corrosion standby liquid control, flux cracking, cyclic monitor, and drain line loading exposed to reactor coolant (3.1.1-40) 3-143* '.' Group" '-.' Effect! , <> :AMp.'iil GALL.' L ':, (GALt No.) 'Mechanism 1 ':, b/ ' ' < Report** .

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Nickel alloy, stainless steel Cracking due to pressurizer spray head stress corrosion Water Chemistry and Yes One-Time Inspection (3.1.1-36) . cracking and primary water stress corrosion cracking and, for nickel alloy welded spray heads, comply with applicable NRC 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) Steel (with or without stainless steel cladding) control rod drive return line nozzles exposed to reactor coolant (3.1.1-38) Steel (with or without stainless steel cladding) feedwater nozzles exposed to reactor coolant Stainless steel and nickel alloy penetrations for control rod drive stub tubes instrumentation, jet pump instrumentation, standby liquid control, flux monitor, and drain line exposed to reactor coolant (3.1.1-40) Cracking due to stress corrosion cracking, primary water stress corrosion

cracking, assisted stress corrosion cracking Orders and provide a commitment in the UFSAR Supplement to implement applicable (1) Bulletins and Generic Letters and (2) staff-accepted industry guidelines.

Water Chemistry and UFSAR Supplement commitment to (1) participate in industry RVI aging programs (2) implement applicable results (3) submit for NRC approval> 24 months before the extended period an RVI inspection plan based on industry recommendation. Cracking due to BWR Control Rod cyclic loading Drive Return Line Nozzle Cracking due to BWR Feedwater cyclic loading Nozzle Cracking due to stress corrosion cracking, Intergranular stress corrosion cracking, cyclic loading BWR Penetrations and Water Chemistry 3-143 Yes No No No Not applicable Not applicable to TMI-1 (See SER Section 3.1.2.2.16) Water Chernistry Consistent with UFSAR GALL Report Supplement (See SER Section A.5, Section Commitment 3.1.2.2.17) Number 36 Not applicable Not applicable Not applicable Not applicable to PWRs Not applicable to PWRs Not applicable to PWRs Copoen Gou Ain Efct/ AMP in. GALL Fu7r~the AMP inLA -Staff" (GALL'Rpr -t o) ehns Report. Ev"aluation Sbjpplemen~ts;,' Evalijatlion ReprtIte N.) MecansmInGALLor .Rpoft- -menidmeh-ts Stainless steel and nickel Cracking due to BWR Stress No Not applicable Not applicablealloy piping, piping stress corrosion Corrosion Cracking to PWRs components, and piping cracking and and Water Chemistry elements greater than or intergranular equal to 4 NPS; nozzle stress corrosion safe ends and associated cracking welds (3.1.1-41) Stainless steel and nickel Cracking due to BWR Vessel ID No Not applicable Not applicable alloy vessel shell stress corrosion Attachment Welds to PWRs attachment welds exposed cracking and and Water Chemistry to reactor coolant intergranular (3.1.1-42) stress corrosion cracking Stainless steel fuel. Cracking due to BWR Vessel No Not applicable Not applicable supports and control rod stress corrosion Internals and Water to PWRs drive assemblies control cracking and Chemistry rod drive housing exposed intergranular to reactor coolant stress corrosion (3.1.1-43) crackingStainless steel and nickel Cracking due to BWR Vessel No Not applicable Not applicable alloy core shroud, core stress corrosion Internals and Water to PWRs plate, core plate bolts, cracking, Chemistry support structure, top intergranular guide, core spray lines, stress corrosion spargers, jet pump cracking, assemblies, control rod irradiation-drive housing, nuclear assisted stressinstrumentation guide corrosion tubes cracking (3,1.1-44) Steel piping, piping Wall thinning Flow-Accelerated No Not applicable Not applicable components, and piping due to flow- Corrosion to PWRselements exposed to accelerated reactor coolant corrosion (3.1.1-45) Nickel alloy core shroud Cracking due to Inservice No Not applicable Not applicable and core plate access stress corrosion Inspection (IWB, to PWRshole cover (mechanical cracking, IWC, and IWD), and covers) intergranular Water Chemistry (3.1.1-46) stress corrosion cracking, irradiation-assisted stress corrosion cracking Stainless steel and nickel- Loss of material Inservice No Not applicable Not applicable alloy reactor vessel due to pitting Inspection (IWB, to PWRs internals exposed to and crevice IWC, and IWD), and reactor coolant corrosion Water Chemistry (3.1.1-47) 3-144 Stainless steel and nickel Cracking due to alloy piping, piping stress corrosion components, and piping cracking and elements greater than or intergranular equal to 4 NPS; nozzle stress corrosion safe ends and associated cracking welds (3.1.1-41 ) Stainless steel and nickel Cracking due to alloy vessel shell stress corrosion attachment welds exposed cracking and to reactor coolant intergranular (3.1.1-42) stress corrosion cracking Stainless steel fuel Cracking due to supports and control rod stress corrosion drive assemblies control cracking and rod drive housing exposed intergranular to reactor coolant stress corrosion (3.1.1-43) cracking Stainless steel and nickel Cracking due to alloy core shroud, core stress corrosion plate, core plate bolts, cracking, support structure, top intergranular guide, core spray lines, stress corrosion spargers, jet pump cracking, assemblies, control rod irradiation-drive housing, nuclear assisted stress instrumentation guide corrosion tubes cracking (3.1.1-44) Steel piping, piping Wall thinning components, and piping due to flow-elements exposed to accelerated reactor coolant corrosion (3.1.1-45) Nickel alloy core shroud Cracking due to and core plate access stress corrosion hole cover (mechanical cracking, covers) intergranular (3.1.1-46) stress corrosion cracking, irradiation-assisted stress corrosion cracking Stainless steel and nickel-Loss of material alloy reactor vessel due to pitting internals exposed to and crevice reactor coolant corrosion (3.1.1-47) BWR Stress Corrosion Cracking and Water Chemistry BWR Vessel 10 Attachment Welds and Water Chemistry BWRVessel Internals and Water Chemistry BWR Vessel Internals and Water Chemistry Flow-Accelerated Corrosion Inservice Inspection (IWB, IWC,and IWD), find Water Chemistry Inservice Inspection (IWB, IWC, and IWD), and Water Chemistry 3-144 No No No No No No No Not applicable Not applicable to PWRs Not applicable Not applicable to PWRs Not applicable Not applicable to PWRs Not applicable Not applicable to PWRs Not applicable Not applicable to PWRs Not applicable Not applicable to PWRs Not applicable Not applicable to PWRs Component Group Agilng Effeictl AMP in ýG'ALL Frhr AMP in LRA, Stff Evaluationn (GALL Report Item No.) M.e.ichanismi

.upplemnt

.EvUation Re6port Amendments Steel and stainless steel Cracking due to Inservice No Not applicable Not applicable Class 1 piping, fittings and stress corrosion Inspection (IWB, to PWRs branch connections cracking, IWC, and IWD),< NPS 4 exposed to intergranular Water chemistry, and reactor coolant stress corrosion One-Time Inspection (3.1.1-48) cracking (for of ASME Code stainless steel Class 1 Small-bore only), and Piping thermal and mechanical loading Nickel alloy core shroud Cracking due to Inservice No Not applicable Not applicable and core plate access stress corrosion Inspection (IWB, to PWRs hole cover (welded cracking, IWC, and IWD), covers) intergranular Water Chemistry, (3.1.1-49) stress corrosion and, for BWRs with a cracking, crevice in the access irradiation-hole covers, assisted stress augmented corrosion inspection using UT cracking or other demonstrated acceptable inspection of the access hole cover welds High-strength low alloy Cracking due to Reactor Head No Not applicable Not Applicable steel top head closure stress corrosion Closure Studs to PWRs studs and nuts exposed to cracking and air with reactor coolant intergranular leakage stress corrosion (3.1.1-50) cracking Cast austenitic stainless Loss of fracture Thermal Aging and No Not applicable Not applicable steel jet pump assembly toughness due Neutron Irradiation to PWRs castings; orificed fuel to thermal aging Embrittlement of support and neutron CASS (3.1.1-51) irradiation embrittlement Steel and stainless steel Cracking due to Bolting Integrity No Bolting Integrity Consistent with reactor coolant pressure stress corrosion Program GALL Report boundary (RCPB) pump cracking, loss of and valve closure bolting, material due to manway and holding wear, loss of bolting, flange bolting, and preload due to closure bolting in high- thermal effects, pressure and high- gasket creep, temperature systems and self-(3.1.1-52) loosening 3-145 Steel and stainless steel Cracking due to Class 1 piping, fittings and stress corrosion branch connections cracking, < NPS 4 exposed to intergranular reactor coolant stress corrosion (3.1.1-48) cracking (for stainless steel only), and thermal and mechanical loading Nickel alloy core shroud Cracking due to and core plate access stress corrosion hole cover (welded cracking, covers) intergranular (3.1.1-49) stress corrosion cracking, irradiation-assisted stress corrosion cracking High-strength low alloy Cracking due to steel top head closure stress corrosion studs and nuts exposed to cracking and air with reactor coolant intergranular leakage stress corrosion (3.1.1-50) cracking Cast austenitic stainless Loss of fracture steel jet pump assembly toughness due castings; oriticed fuel to thermal aging support and neutron (3.1.1-51) irradiation embrittlement Steel and stainless steel Cracking due to reactor coolant pressure stress corrosion boundary (RCPB) pump cracking, loss of and valve closure bolting, material due to manway and holding wear, loss of bolting, flange bolting, and preload due to closure bolting in high-thermal effects, pressure and high-gasket creep, temperature systems and self-(3.1.1-52) loosening Inservice Inspection (IWB, IWC, and IWD), Water chemistry, and One-Time Inspection of AS ME Code Class 1 Small-bore Piping Inservice Inspection (IWB, IWC, and IWD), Water Chemistry, and, for BWRs with a crevice in the access hole covers, augmented inspection using UT or other demonstrated acceptable inspection of the access hole cover welds Reactor Head Closure Studs Thermal Aging and Neutron Irradiation Embrittlement of CASS Bolting Integrity 3-145 No No No No No Not applicable Not applicable to PWRs Not applicable Not applicable to PWRs Not applicable Not Applicable to PWRs Not applicable Not applicable to PWRs Bolting Integrity Consistent with Program GALL Report Component Group .AgingEffectl AMP in GALL Further Staff'(GALL Report Item No.)' Mechanism Report- Evaluation Su;pplements, Evaluation 4.. -in-G'ALL o* ,~. Relport Am~endmenpts Steel piping, piping Loss of material Closed-Cycle No Not applicable Not applicable components, and piping due to general, Cooling Water to TMI-1 (See elements exposed to pitting and System SER Section closed cycle cooling water crevice 3.1.2.1.1) (3.1.1-53) corrosion Copper alloy piping, piping Loss of material Closed-Cycle No Not applicable Not applicable components, and piping due to pitting, Cooling Water to TMI-1 (See elements exposed to crevice, and System SER Section closed cycle cooling water galvanic 3.1.2.1.1) (3.1.1-54) corrosion Cast austenitic stainless Loss of fracture Inservice No Inservice Consistent with steel Class 1 pump toughness due Inspection (IWB, Inspection, GALL Report casings, and valve bodies to thermal aging IWC, and IWD). Subsections and bonnets exposed to embrittlement Thermal aging IWB, IWC, and reactor coolant > 250°C susceptibility IWD (> 482°F) screening is not (3.1.1-55) necessary, inservice inspection requirements are sufficient for managing these aging effects. ASME Code Case N-481 also provides an alternative for pump casings.Copper alloy > 15% Zn Loss of material Selective Leaching of No Not applicable. Not applicable piping, piping due to selective Materials to TMI-1 (See components, and piping leaching SER Section elements exposed to 3.1.2.1.1) closed cycle cooling water (3.1.1-56) Cast austenitic stainless Loss of fracture Thermal Aging No Not applicable Not applicable steel Class 1 piping, toughness due Embrittlement of to TMI-1 (See piping component, and to thermal aging CASS SER Section piping elements and embrittlement 3.1.2.1.1) control rod drive pressure housings exposed to reactor coolant > 250°C (> 482°F)(3.1.1-57) Steel reactor coolant Loss of material Boric Acid Corrosion No Boric Acid Consistent with pressure boundary due to boric acid Corrosion GALL Report external surfaces exposed corrosion to air with borated water leakage (3.1.1-58) 3-146 Steel piping, piping Loss of material components, and piping due to general, elements exposed to pitting and closed cycle cooling water crevice (3.1.1-53) corrosion Copper alloy piping, piping Loss of material components, and piping due to pitting, elements exposed'to crevice, and closed cycle cooling water galvanic (3.1.1-54) corrosion Cast austenitic stainless Loss of fracture steel Class 1 pump toughness due casings, and valve bodies to thermal aging and bonnets exposed to embrittlement reactor coolant> 250°C (> 482°F) (3.1.1-55) Copper alloy> 15% Zn Loss of material piping, piping due to selective components, and piping leaching elements exposed to closed cycle cooling water (3.1.1-56) Cast austenitic stainless Loss of fracture steel Class 1 piping, toughness due piping component, and to thermal aging piping elements and embrittlement control rod drive pressure housings exposed to reactor coolant> 250°C (> 482°F) (3.1.1-57) Steel reactor coolant Loss of material pressure boundary due to boric acid extemal surfaces exposed corrosion to air with borated water leakage (3.1.1-58) Closed-Cycle No Cooling Water System Closed-Cycle ' No Cooling Water System Inservice No Inspection (IWB, IWC, and IWO). 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 altemative for pump casings. Selective Leaching of No Materials Thermal Aging No Embrittlement of CASS Boric Acid Corrosion No 3-146 Not applicable Not applicable Inservice Inspection, Subsections IWB, IWC, and IWO Not applicable. Not applicable Boric Acid Corrosion Not applicable to TMI-1 (See SER Section 3.1.2.1.1) Not applicable to TMI-1 (See SER Section 3.1.2.1.1 ) Consistent with GALL Report Not applicable to TMI-1 (See SER Section 3.1.2.1.1 ) Not applicable to TMI-1 (See SER Section 3.1.2.1.1) Consistent with GALL Report Con fetGru Agn fet M nGLL uthr APiLA, Siaf Mt Evauaton No)upple i '6'o6ments, Evaluation~(GALL~ ~ ~ ~ ~ ~ ~~e Retr memN. caim .epr nGL___________________~~A _______ _ Rpot Aedm'ents. Steel steam generator Wall thinning Flow-Accelerated No Not Applicable Not applicable steam nozzle and safe due to flow- Corrosion to TMI-1 (See end, feedwater nozzle and accelerated SER Section safe end, AFW nozzles corrosion 3.1.2.1.2) and safe ends exposed to secondary feedwater/steam (3.1.1-59) Stainless steel flux thimble Loss of material Flux Thimble Tube No Not applicable Not applicable tubes (with or without due to wear Inspection to TMI-1 (See chrome plating) SER Section (3.1.1-60) 3.1.2.1.1)Stainless steel, steel Cracking due to Inservice No Inservice Consistent with pressurizer integral cyclic loading Inspection (IWB, Inspection, GALL Report support exposed to air IWC, and IWD) Subsections with metal temperature up IWB, IWC, andto 288°C (550°F) IWD (3.1.1-61) Stainless steel, steel with Cracking due to Inservice No Inservice Consistent with stainless steel cladding cyclic loading Inspection (IWB, Inspection, GALL Report reactor coolant system IWC, and IWD) Subsections cold leg, hot leg, surge IWB, IWC, and line, and spray line piping IWD and fittings exposed to reactor coolant (3.1.1-62) Steel reactor vessel Loss of material Inservice No Not applicable Not applicable flange, stainless steel and due to wear Inspection (IWB, to TMI-1 (See nickel alloy reactor vessel IWC, and IWD) SER Section internals exposed to 3.1.2.1.1) reactor coolant (e.g., upper and lower internals assembly, CEA shroud assembly, core support barrel, upper grid assembly, core support shield assembly, lower grid assembly)(3.1.1-63) Stainless steel and steel Cracking due to Inservice No Inservice Consistent with with stainless steel or stress corrosion Inspection (IWB, Inspection, GALL Report nickel alloy cladding cracking, IWC, and IWD) and Subsections pressurizer components primary water Water Chemistry IWB, IWC, and (3.1.1-64) stress corrosion IWD L_ cracking Water Chemistry, 3-147 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) Stainless steel flux thimble tubes (with or without chrome plating) (3.1.1-60) Stainless steel, steel pressurizer integral support exposed to air with metal temperature up to 288°C (550°F) (3.1.1-61) 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) Steel reactor vessel flange, stainless steel and nickel alloy reactor vessel intemals exposed to reactor coolant (e.g., upper and lower intemals assembly, CEA shroud assembly, core support barrel; upper grid assembly, core support shield assembly, lower grid assembly) (3.1.1-63) Stainless steel and steel with stainless steel or nickel alloy cladding pressurizer components (3.1.1-64) Wall thinning due to accelerated corrosion Flow-Accelerated Corrosion Loss of material Flux Thimble Tube due to wear Inspection Cracking due to Inservice cyclic loading Inspection (IWB, IWC, and IWD) Cracking due to cyclic loading Inservice Inspection (IWB, IWC, and IWD) Loss of material Inservice due to wear Inspection (IWB, IWC, and IWD) Cracking due to stress corrosion cracking, primary water stress corrosion cracking Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry 3-147 No No No No No No Not Applicable Not applicable Inservice

Inspection, Subsections IWB, IWC, and IWD Inservice Inspection, Subsections IWB, IWC, and IWD Not applicable Inservice Inspection, Subsections IWB, IWC, and IWD Water Chemistry Not applicable toTMI-1 (See SER Section 3.1.2.1.2) Not applicable to TMI-1 (See SER Section 3.1.2.1.1 ) Consistent with GALL Report Consistent with GALL Report Not applicable to TMI-1 (See SER Section 3.1.2.1.1) Consistent with GALL Report Component Group Aging Effect , AMin GA ::LL Further :AMP in LRA, Staff (GALL Repodrt Itemio No.) Mechanism Report Evaluation SUpplements, Evaluation in, GALLor___.____ Report.:" :Amendments, Nickel alloy reactor vessel Cracking due to Inservice No Inservice Consistent withupper head and control primary water Inspection (IWB, Inspection, GALL Report rod drive penetration stress corrosion IWC, and IWD) and Subsections nozzles, instrument tubes, cracking Water Chemistry and IWB, IWC, and head vent pipe (top head), Nickel-Alloy IWD and welds Penetration Nozzles Water Chemistry (3.1.1-65) Welded to the Upper Nickel-Alloy Reactor Vessel Penetration Closure Heads of Nozzles Welded Pressurized Water to the Upper Reactors Reactor Vessel Closure Heads of Pressurized Water Reactors Steel steam generator Loss of material Inservice No Not applicable Not applicable secondary manways and due to erosion Inspection (IWB, to TMI-1 (See handholds (cover only) IWC, and IWD) for SER Section exposed to air with leaking Class 2 components 3.1.2.1.1) secondary-side water and/or steam (3,1.1-66) Steel with stainless steel Cracking due to Inservice No Not applicable Not applicable or nickel alloy cladding; or cyclic loading Inspection (IWB, to TMI-1 (See stainless steel pressurizer IWC, and IWD), and SER Section components exposed to Water Chemistry 3.1.2.1.1) reactor coolant (3.,11.1-67)Stainless steel, steel with Cracking due to Inservice No Inservice Consistent with stainless steel cladding stress corrosion Inspection (IWB, Inspection, GALL Report Class 1 piping, fittings, cracking IWC, and IWD), and Subsections pump casings, valve Water Chemistry IWB, IWC, and bodies, nozzles, safe IWD ends, manways, flanges, Water Chemistry 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) Stainless steel, nickel Cracking due to Inservice No Inservice Consistent with alloy safety injection stress corrosion Inspection (IWB, Inspection, GALL Report nozzles, safe ends, and Cracking, IWC, and IWD), and Subsections associated welds and primary water Water Chemistry IWB, IWC, and buttering exposed to stress corrosion IWD reactor coolant cracking Water Chemistry (3.1.1-69) 1 1 1 1_1 3-148 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) Steel steam generator secondary manways and hand holds (cover only) exposed to air with leaking secondary-side water and/or steam (3.1.1-66) Steel with stainless steel or nickel alloy cladding; or stainless steel pressurizer components exposed to reactor coolant (3,1.1-67) 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) 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 primary water stress corrosion cracking Loss of material due to erosion Cracking due to cyclic loading Cracking due to stress corrosion cracking Cracking due to stress corrosion cracking, primary water stress corrosion cracking Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry and Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Inservice Inspection (IWB, IWC, and IWD) for Class 2 components Inservice Inspection (IWB, IWC, and IWD), and Water Chemistry Inservice Inspection (IWB, IWC, and IWD), and Water Chemistry Inservice Inspection (IWB, IWC, and IWD), and Water Chemistry 3-148 No No No No No Inservice Inspection, Subsections IWB, IWC, and IWD Water Chemistry Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Not applicable Not applicable Inservice Inspection, Subsections IWB, IWC, and IWD Water Chemistry Inservice Inspection, Subsections IWB, IWC, and IWD Water Chemistry Consistent with GALL Report Not applicable to TMI-1 (See SER Section 3.1.2.1.1) Not applicable to TMI-1 (See SER Section 3.1.2.1.1 ) Consistent with GALL Report Consistent with GALL Report Istgniss itee ildd C thEffertl AMP in GALL AMspect in LkA ALSta~~,(GALL~~~~-' Reotle~. eh~ir ~Eauatn Supplements,'-Evaluation,-inGAILL: or.-Repof Amendments Stainless steel; steel with Cracking due to Inservice No Inservice, Consistent with stainless steel cladding SCC, thermal Inspection (IWB, Inspection, GALL Report Class 1 piping, fittings and and mechanical IWC, and IWD), Subsections (See SER branch connections < NPS loading Water chemistry, and IWB, IWC, and Section 4 exposed to reactor One-Time Inspection IWD 3.1.2.1.3) coolant of ASME Code Water Chemistry (3.1.1-70) Class 1 Small-bore Piping High-strength low alloy Cracking due to Reactor Head No Reactor Head Consistent with steel closure head stud stress corrosion Closure Studs Closure Studs GALL Report assembly exposed to air cracking; loss of with reactor coolant material due to leakage wear (3.1.1-71) Nickel alloy steam Cracking due to Steam Generator No Steam Consistent with generator tubes and OD stress Tube Integrity and Generator Tube GALL Report sleeves exposed to corrosion Water Chemistry Integrity secondary cracking and Water Chemistry feedwater/steam intergranular (3.1.1-72) attack, loss of material due to fretting and wear Nickel alloy steam Cracking due to Steam Generator No Steam Consistent with generator tubes, repair primary water Tube Integrity and Generator Tube GALL Report sleeves, and tube plugs stress corrosion Water Chemistry Integrity exposed to reactor coolant cracking Water Chemistry (3.1.1-73) Chrome plated steel, Cracking due to Steam Generator No Steam Not applicable stainless steel, nickel alloy stress corrosion Tube Integrity and Generator Tube to TMI-1 (See steam generator anti- cracking, loss of Water Chemistry Integrity SER Section vibration bars exposed to material due to Water Chemistry 3.1.2.1.1) secondary crevice feedwater/steam corrosion and (3.1.1-74) frettingNickel alloy once-through Denting due to Steam Generator No Steam Consistent with steam generator tubes corrosion of Tube Integrity and Generator Tube GALL Report exposed to secondary carbon steel Water Chemistry Integrity feedwater/steam tube support Water Chemistry (3.1.1-75) plate Steel steam generator Loss of material Steam Generator No Not applicable Not applicable tube support plate, tube due to erosion, Tube Integrity and to TMI-1 (See bundle wrapper exposed general, pitting, Water Chemistry SER Section to secondary and crevice 3.1.2.1.1) feedwater/steam corrosion, (3.1.1-76) ligament cracking due to corrosion 3-149 Stainless steel; steel with Cracking due to stainless steel cladding SCC, thermal Class 1 piping, fittings and and mechanical branch connections <: NPS loading 4 exposed to reactor coolant (3.1.1-70) High-strength low alloy Cracking due to steel closure head stud stress corrosion assembly exposed to air cracking; loss of with reactor coolant material due to leakage wear (3.1.1-71 ) Nickel alloy steam Cracking due to generator tubes and 00 stress sleeves exposed to corrosion secondary cracking and feedwateristeam intergranular (3.1.1-72) attack, loss of material due to fretting and wear Nickel alloy steam Cracking due to generator tubes, repair primary water sleeves, and tube plugs stress corrosion exposed to reactor coolant cracking (3.1.1-73) Chrome plated steel, stainless steel, nickel alloy steam generator vibration bars exposed to secondary feedwateristeam (3.1.1-74) Nickel alloy once-through steam generator tubes exposed to secondary feedwater/steam (3.1.1-75) Steel steam generator tube support plate, tube bundle wrapper exposed to secondary feedwateristeam (3.1.1-76) Cracking due to stress corrosion cracking, loss of material due to crevice corrosion and fretting Denting due to corrosion of carbon steel tube support plate Loss of material due to erosion, general, pitting, and crevice corrosion, ligament cracking due to corrosion Inservice

Inspection (IWB, IWC, and IWO), Water chemistry, and One-Time Inspection of ASME Code Class 1 Small-bore Piping Reactor Head Closure Studs Steam Generator Tube Integrity and Water Chemistry Steam Generator Tube Integrity and Water Chemistry Steam Generator Tube Integrity and Water Chemistry Steam Generator Tube Integrity and Water Chemistry Steam Generator Tube Integrity and Water Chemistry 3-149 No No No No No No No Inservice Consistent with Inspection, GALL Report Subsections (See SER IWB, IWC, and Section IWD 3.1.2.1.3) Water Chemistry Reactor Head Closure Studs Steam Generator Tube Integrity Water Chemistry Consistent with GALL Report Consistent with GALL Report Steam Consistent with Generator Tube GALL Report Integrity Water Chemistry Steam Not applicable Generator Tube to TMI-1 (See Integrity SER Section Water Chemistry 3.1.2.1.1) Steam Generator Tube Integrity Water Chemistry Not applicable Consistent with GALL Report Not applicable to TMI-1 (See SER Section 3.1.2.1.1 ) Compoent roup gingEffect/ AMP in GALL ý, Furthier AMP.i R, tfNickel alloy steam Loss of material Steam Generator No Not applicable Not applicable generator tubes and due to wastage Tube Integrity and to TMI-1 (See sleeves exposed to and pitting Water Chemistry SER Section phosphate chemistry in corrosion 3.1.2.1.1) secondary feedwater/steam (3.1.1-77) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Steel steam generator Wall thinning Steam Generator No Not applicable Not applicable tube support lattice bars due to flow- Tube Integrity and to TMI-1 (See exposed to secondary accelerated Water Chemistry SER Section feedwater/steam corrosion 3.1.2.1.1) (3.1.1-78) Nickel alloy steam Denting due to Steam Generator No Not applicable Not applicable generator tubes exposed corrosion of Tube Integrity; Water to TMI-1 (See to secondary steel tube Chemistry and, for SER Sectionfeedwater/steam support plate plants that could 3.1.2.1.1) (3.1.1-79) experience denting at the upper support plates, evaluate potential for rapidly propagating cracks and then develop and take correctiveactions consistent with NRC Bulletin 88-02.Cast austenitic stainless Loss of fracture Thermal Aging and No UFSAR Consistent with steel reactor vessel toughness due Neutron Irradiation Supplement GALL Report internals (e.g., upper to thermal aging Embrittlement of Section A.5, internals assembly, lower and neutron CASS Commitment internal assembly, CEA irradiation Number 36 shroud assemblies, embrittlement control rod guide tube assembly, core support shield assembly, lower grid assembly)(3.1.1-80)Nickel alloy or nickel-alloy Cracking due to Water Chemistry No Not applicable Not applicable clad steam generator primary water to TMI-1 (See divider plate exposed to stress corrosion SER Section reactor coolant cracking 3.1.2.1.1) (3.1.1-81) Stainless steel steam Cracking due to Water Chemistry No Not applicable Not applicable generator primary side stress corrosion to TMI-1 (See divider plate exposed to cracking SER Section reactor coolant 3.1.2.1.1) (3.1.1-82) 3-150 Nickel alloy steam generator tubes and sleeves exposed to phosphate chemistry in secondary feedwater/steam (3.1.1-77) Steel steam generator tube support lattice bars exposed to secondary feedwater/steam (3.1.1-78) Nickel alloy steam generator tubes exposed to secondary feedwater/steam (3.1.1-79) 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) Nickel alloy or nickel-alloy clad steam generator divider plate exposed to reactor coolant (3.1.1-81) Stainless steel steam generator primary side divider plate exposed to reactor coolant (3.1.1-82) Loss of material Steam Generator due to wastage Tube Integrity and and pitting Water Chemistry corrosion No Wall thinning due to accelerated corrosion Steam Generator No Denting due to corrosion of steel tube support plate Loss of fracture toughness due to thermal aging and neutron irradiation embrittlemerit Cracking due to primary water stress corrosion cracking Tube Integrity and Water Chemistry Steam Generator No 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. Thermal Aging and No Neutron Irradiation Embrittlement of CASS Water Chemistry No Cracking due to Water Chemistry stress corrosion No cracking 3-150 Not applicable Not applicable to TMI-1 (See SER Section 3.1.2.1.1) Not applicable Not applicable UFSAR Supplement Section A.5, Commitment Number 36 Not applicable Not applicable to TMI-1 (See SER Section ) Not applicable to TMI-1 (See SER Section 3.1.2.1.1) Consistent with GALL Report Not applicable to TMI-1 (See SER Section 3.1.2.1.1) Not applicable Not applicable to TMI-1 (See SER Section 3.1.2.1.1 ) .Component'Group. Aging Effect/ AMP in GALL Further AMP inLRA, Staff ~(GALL Report item No.), Mechanism Report invaluatio Supplements, ýEvaluation. in GAL,,, orý: 4 Report Amendments Stainless steel; steel with Loss of material Water Chemistry No Water Chemistry Consistent with nickel-alloy or stainless due to pitting GALL Report steel cladding; and nickel- and crevice alloy reactor vessel corrosion internals and reactor coolant pressure boundary components exposed to reactor coolant (3.1.1-83) Nickel alloy steam Cracking due to Water Chemistry and No Water Chemistry Consistent withgenerator components stress corrosion One-Time Inspection One-Time GALL Report such as, secondary side cracking or Inservice Inspection, or nozzles Inspection (IWB, Water Chemistry (vent, drain, and IWC, and IWD). and Inservice instrumentation) exposed Inspection, to secondary Subsections feedwater/steam IWB, IWC, and (3.1.1-84) IWD, or Water Chemistry and Steam Generator Tube Integrity Nickel alloy piping, piping None None No None Not applicable components, and piping to TMI-1 (See elements exposed to air -SER Section indoor uncontrolled 3.1.2.1.1)(external) (3.1.1-85) Stainless steel piping, None None No None Consistent with piping components, and GALL Report piping elements exposed to air -indoor uncontrolled (External); air with borated water leakage; concrete; gas (3.1.1-86) Steel piping, piping None None No Not applicable Not applicablecomponents, and piping to TMI-1 (See elements in concrete SER Section (3.1.1-87) 3.1.2.1.1) The staffs review of the RCS component groups followed several approaches. One approach, documented in SER Section 3.1.2.1, discusses the staffs review of AMR results for components the applicant indicated are consistent with the GALL Report and require no further evaluation. Another approach, documented in SER Section 3.1.2.2, discusses the staff's review of AMR results for components the applicant indicated are consistent with the GALL Report and for whichfurther evaluation is recommended. A third approach, documented in SER Section 3.1.2.3, discusses the staff's review of AMR results for components 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 RCS components is documented in SER Section 3.0.3.3-151 Stainless steel; steel with nickel-alloy or stainless steel cladding; and alloy reactor vessel intemals and reactor coolant pressure boundary components exposed to reactor coolant Loss of material Water Chemistry due to pitting No (3.1.1-83) Nickel alloy steam generator components such as, secondary side nozzles (vent, drain, and instrumentation) exposed to secondary feedwater/steam (3.1.1-84) and crevice corrosion Cracking due to stress corrosion cracking Nickel alloy piping, piping None components, and piping elements exposed to air -indoor uncontrolled (extemal) (3.1.1-85) Stainless steel piping, None piping components, and piping elements exposed to air -indoor uncontrolled (Extemal); air with borated water leakage; concrete; gas (3.1.1-86) Steel piping, piping None components, and piping elements in concrete (3.1.1-87) Water Chemistry and No One-Time Inspection or Inservice Inspection (IWe, IWC, and IWD). None No None No None No Water Chemistry Consistent with GALL Report Water Chemistry Consistent with One-Time GALL Report Inspection, or Water Chemistry andlnservice Inspection, Subsections IWB, IWC, and IWD ,or Water Chemistry and Steam Generator Tube Integrity None Not applicable to TMI-1 (See SER Section 3.1.2.1.1) None Consistent with GALL Report Not applicable Not applicable to TMI-1 (See SER Section 3.1.2.1.1 ) The staff's review of the RCS component groups followed several approaches. One approach, documented in SER Section 3.1.2.1, discusses the staff's review of AMR results for components the applicant indicated are consistent with the GALL Report and require no further evaluation. Another approach, documented in SER Section 3.1.2.2, discusses the staff's review of AMR results for components the applicant indicated are consistent with the GALL Report and for which further evaluation is recommended. A third approach, documented in SER Section 3.1.2.3, discusses the staff's review of AMR results for components the applicant indicated are not consistent with or not addressed in the GALL Report. The staff's review of AMPs credited to manage or monitor aging effects of the RCS components is documented in SER Section 3.0.3. 3-151 3.1.2.1 AMR Results That Are 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:

  • ASME Section XI, Inservice Inspection, Subsections IWB, IWC, and IWD* Bolting Integrity Program" Boric Acid Corrosion Program* External Surfaces Monitoring
  • Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" Lubricating Oil Analysis* Nickel Alloy Aging Management Program" Nickel Alloy Penetration nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors" One-Time Inspection Program* Reactor Head Closure Studs* Reactor Vessel Surveillance
  • Steam Generator Tube Integrity* Time Limited Aging Analysis* Water Chemistry Program LRA Tables 3.1.2-1 through 3.1.2-4, summarize the results of AMRs for the reactor coolant system, reactor vessel, reactor vessel internal, and steam generator components and indicate AMRs claimed to be consistent with the GALL Report.For component groups evaluated in the GALL Report for which the applicant had claimed consistency and for which the GALL Report does not recommend further evaluation, the staff performed an audit and review to determine whether the plant-specific components in these GALL Report component groups were bounded by the GALL Report evaluation.

The applicant provided a note for each AMR line item describing how the information in the tables aligns with the information in the GALL Report. The staff reviewed those AMRs with Notes A through E, which indicate how the AMR was consistent with the GALL Report.Note A indicates that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP is consistent with the GALL Report 3-152 3.1.2.1 AMR Results That Are 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:

  • ASME Section XI, Inservice Inspection, Subsections IWB, IWC, and IWD
  • Bolting Integrity Program
  • Boric Acid Corrosion Program
  • External Surfaces Monitoring
  • Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components
  • Lubricating Oil Analysis
  • Nickel Alloy Aging Management Program
  • Nickel Alloy Penetration nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors
  • One-Time Inspection Program
  • Reactor Head Closure Studs
  • Reactor Vessel Surveillance
  • Steam Generator Tube Integrity
  • Time limited Aging Analysis
  • Water Chemistry Program LRA Tables 3.1.2-1 through 3.1.2-,4, summarize the results of AMRs for the reactor coolant system, reactor vessel, reactor vessel internal, and steam generator components and indicate AMRs claimed to be consistent with the GALL Report. For component groups evaluated in the GALL Report for which the applicant had claimed consistency and for which the GALL Report does not recommend further evaluation, the staff performed an audit and review to determine whether the plant-specific components in these GALL Report component groups were bounded by the GALL Report evaluation.

The applicant provided a note for each AMR line item describing how the information in the tables aligns with the information in the GALL Report. The staff reviewed those AMRs with Notes A through E, which indicate how the AMR was consistent with the GALL Report. Note A indicates that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP is consistent with the GALL Report 3-152 AMP. The staff reviewed these line items to verify consistency with the GALL Report and the 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 AMP identified in the GALL Report. The staff reviewed these line items to verify consistency with the GALL Report and that it had reviewed and accepted the identified exceptions to the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant was consistent with the AMP identified in the GALL Report 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 AMP identified by the GALL Report. This note indicates that the applicant was unable to find a listing of some system components in the GALL Report; however, the applicant identified a different component in the GALL Report that had the same material, environment, aging effect, and AMP as the component under review. The staff reviewed these line items to verify consistency with the GALL Report. The staff also determined whether the AMR line item of the different component applied 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 AMP identified in the GALL Report. The staff reviewed these line items to verify consistency with the GALL Report. The staff confirmed whether the AMR line item of the different component was applicable to the component under review and whether the exceptions to the GALL Report AMPs had been reviewed and accepted by the staff. The staff also determinedwhether the AMP identified by the applicant was consistent with the AMP identified in the GALLReport 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 a different AMP is credited. The staff reviewed these line items to verify consistency with the GALL Report and determined whether the identified AMP would manage the aging effect consistent with the AMP identified in the GALL Report 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 ofthe matters described in the GALL Report; however, it did verify that the material presented in the LRA was applicable and that the applicant had identified the appropriate GALL Report AMRs. The staff's evaluation is discussed below.The staff reviewed the LRA to confirm that the applicant: (a) provided a brief description of thesystem, 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 coolant system, reactor vessel, reactor vessel internals, and steam generator components that are subject to an AMR.On the basis of its audit and review, the staff determines that, for AMRs not requiring further evaluation, as identified in LRA Table 3.1.1, the applicant's references to the GALL Report are acceptable and no further staff review is required.3-153 AMP. The staff reviewed these line items to verify consistency with the GALL Report and the 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 AMP identified in the GALL Report. The staff reviewed these line items to verify consistency with the GALL Report and that it had reviewed and accepted the identified exceptions to the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant was consistent with the AMP identified in the GALL Report 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 AMP identified by the GALL Report. This note indicates that the applicant was unable to find a listing of some system components in the GALL Report; however, the applicant identified a different component in the GALL Report that had the same material, environment, aging effect, and AMP as the component under review. The staff reviewed these line items to verify consistency with the GALL Report. The staff also determined whether the AMR line item of the different component applied 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 AMP identified in the GALL Report. The staff reviewed these line items to verify consistency with the GALL Report. The staff confirmed whether the AMR line item of the different component was applicable to the component under review and whether the exceptions to . the GALL Report AMPs had been reviewed and accepted by the staff. The staff also determined whether the AMP identified by the applicant was consistent with the AMP identified in the GALL Report 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 a different AMP is credited. The staff reviewed these line items to verify consistency with the GALL Report and determined whether the identified AMP would manage the aging effect consistent with the AMP identified in the GALL Report 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, it did verify that the material presented in the LRA was applicable and that the applicant had identified the appropriate GALL Report AMRs. The staff's evaluation is discussed below. 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 coolant system, reactor vessel, reactor vessel internals, and steam generator components that are subject to an AMR. On the basis of its audit and review, the staff determines that, for AMRs not requiring further evaluation, as identified in LRA Table 3.1.1, the applicant's references to the GALL Report are acceptable and no further staff review is required. 3-153 3.1.2.1.1 AMR Results Identified as Not Applicable Based on its initial review, the staff could not determine the specific reason why the applicant considered LRA Table 3.1. 1, line items 53, 54, 56, 57, 59, 60, 63, 66, 67, 74, 76, 77 -82, 85, and 87 to be not applicable. In RAI-AMR-GENERIC-1, dated October 16, 2008, the staff requestedthat the applicant provide additional information regarding these not applicable items so the staff could complete its evaluation. In its response to the RAI dated November 12, 2008, the applicant stated that "Not Applicable" has been used when the component, material and environment combination does not exist in the identified GALL system grouping and also when the component, material and environment combination does exist but the LRA Table 3.x.1 item was not used because a different Table 3.x.1 item was selected to manage the identified aging effect/mechanism. Based on its review, the staff finds the applicant's response to RAI-AMR-GENERIC-1 unacceptable because the applicant did not provide the specific reasons it used to consider the subject line items in LRA Table 3.1.1 not applicable and the staff could not complete its review.In RAI-AMR-GENERIC-2, dated January 5, 2009, the staff requested that the applicant indicate for each of the LRA Table 3.x. 1 items where "not applicable" is listed in the "discussion" column, the specific reason why the item is considered not applicable to TMI-I. The staff also requested that if the component, material and environment does exist but the LRA Table 3.x. 1 item was not used, that the applicant indicate what other 3.x.1 item was selected to manage the identified aging effect/mechanism. In its response to the RAI dated January 12, 2009, the applicant provided a table identifying the specific reason(s) why a Table 3.x.1 item is not considered applicable to TMI-1.Based on its review, the staff finds the applicant's response to RAI AMR-GENERIC-2 acceptable because the applicant provided the basis for LRA Table 3.x.1 line items identified as "not applicable." The staff's concern described in RAI AMR-GENERIC-2 is resolved.LRA Table 3.1.1, line items 38 -51, discusses the applicant's determination on GALL AMR line items that are applicable only to BWR-designed reactors. In the applicant AMR discussions for line items 38 -51, no additional information is provided. The staff confirmed that AMR line items 38 -51, in Table 1 of the GALL Report, Volume 1 are only applicable to BWR designed reactors,and that TMI-1 is a pressurized water reactor with a dry ambient containment. 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 TMI-1.LRA Table 3.1.1, line items 74, 77 -79, 81, and 82 discuss the applicant's determination on GALL AMR line items that are applicable only to recirculating steam generators. The staff confirmed that AMR line items 74, 77 -79, 81, and 82, in Table 1 of the GALL Report, Volume 1 are only applicable to recirculating steam generators and confirmed by reviewing various sections of the LRA, that TMI-1 has once through steam generators. Based on this determination, the staff finds that the applicant has provided an acceptable basis for concluding AMR line items 74, 77 -79, 81, and 82 in Table 1 of the GALL Report, Volume 1 are not applicable to TMI-1.LRA Table 3.1.1, line item 53 addresses steel 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 due to general, pitting and crevice corrosion in this component group. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that 3-154 3.1.2.1.1 AMR Results Identified as Not Applicable Based on its initial review, the staff could not determine the specific reason why the applicant considered LRA Table 3.1.1, line items 53,54,56,57,59,60,63,66,67,74,76,77...;.. 82,85, and 87 to be not applicable. In RAI-AMR-GENERIC-1, dated October 16, 2008, the staff requested that the applicant provide additional information regarding these not applicable items so the staff could complete its evaluation. In its response to the RAI dated November 12, 2008, the applicant stated that "Not Applicable" has been used when the component, material and environment combination does not exist in the identified GALL system grouping and also when the component, material and environment combination does exist but the LRA Table 3.x.1 item was not used because a different Table 3.x.1 item was selected to manage the identified aging effect/mechanism. Based on its review, the staff finds the applicant's response to RAI-AMR-GENERIC-1 unacceptable because the applicant did not provide the specific reasons it used to consider the subject line items in LRA Table 3.1.1 not applicable and the staff could not complete its review. In RAI-AMR-GENERIC-2, dated January 5; 2009, the staff requested that the applicant indicate for each of the LRA Table 3.x. 1 items where "not applicable" is listed in the "discussion" column, the specific reason why the item is considered not applicable to TMI-1. The staff also requested that if the component, material and environment does exist but the LRA Table 3.x.1 item was not used, that the applicant indicate what other 3.x.1 item was selected to manage the identified aging effect/mechanism. In its response to the RAI dated January 12, 2009, the applicant provided a table identifying the specific reason(s) why a Table 3.x.1 item is not considered applicable to TMI-1. Based on its review, the staff finds the applicant's response to RAI AMR-GENERIC-2 acceptable because the applicant provided the basis for LRA Table 3.x.1 line items identified as "not applicable." The staff's concern described in RAI AMR-GENERIC-2 is resolved. LRA Table 3.1.1, line items 38 -51, discusses the applicant's determination on GALL AMR line items that are applicable only to BWR-designed reactors. In the applicant AMR discussions for line items 38 -51, no additional information is provided. The staff confirmed that AMR line items 38 -51, in Table 1 of the GALL Report, Volume 1 are only applicable to BWR designed reactors, and that TMI-1 is a pressurized water reactor with a dry ambient containment. 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 TMI-1. LRA Table 3.1.1, line items 74,77 -79,81, and 82 discuss the applicant's determination on GALL AMR line items that are applicable only to recirculating steam generators. The staff confirmed that AMR line items 74, 77 -79, 81, and 82, in Table 1 of the GALL Report, Volume 1 are only applicable to recirculating steam generators and confirmed by reviewing various sections of the LRA, that TMI-1 has once through steam generators. Based on this determination, the staff finds that the applicant has provided an acceptable basis for concluding AMR line items 74, 77 -79,81, and 82 in Table 1 of the GALL Report, Volume 1 are not applicable to TMI-1. LRA Table 3.1.1, line item 53 addresses steel 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 due to general, pitting and crevice corrosion in this component group. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that 3-154 this line item is not applicable because there are no steel piping, piping components, or piping elements exposed to closed cycle cooling water in the reactor vessel, internals and reactor coolant system. The staff reviewed LRA Sections 2.3.1 and 3.1 and confirmed that TMI-1 doesnot have support systems that are part of the reactor vessel, internals and reactor coolant system and steam generators within the scope of license renewal that contain the piping, piping components and piping elements fabricated from steel exposed to closed cycle cooling water.Based on its review of the LRA, the staff confirmed that there are no steel piping, piping components, or piping elements exposed to closed cycle cooling water in the reactor vessel, internals and reactor coolant system and therefore, finds the applicant's determination acceptable. LRA Table 3.1.1, line item 54 addresses 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 due to pitting, crevice, and galvanic corrosion in this component group. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that this line item is not applicable because there are no copper alloy piping, piping components, or piping elements exposed to closed cycle cooling water in the reactor vessel, internals and reactor coolant system. The staff reviewed LRA Sections 2.3.1 and 3.1 and confirmed that TMI-1 does not have support systems that are part of the reactor vessel, internals and reactor coolant system and steam generators with-in the scope of license renewal that contain the piping, piping components and piping elements fabricated from copper alloy exposed to closed cycle cooling water. Based on its review of the LRA, the staff confirmed that there are no steel piping, piping components, or piping elements exposed to closed cycle cooling water in the reactor vessel, internals and reactor coolant system and therefore, finds the applicant's determination acceptable. LRA Table 3.1.1, line item 56 addresses copper alloy greater than 15% zinc piping, piping components, and piping elements exposed to closed cycle cooling water. The GALL Report recommends the Selective Leaching of Materials AMP to manage loss of material due to selective leaching in this component group. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that this line item is not applicable because there are ýno copper alloy greater than 15% zinc piping, piping components, or piping elements exposed to closed cycle cooling water in the reactor vessel, internals and reactor coolant system. The staff reviewed LRA Sections 2.3.1 and 3.1 and confirmed that TMI-1 does not have support systems that are part of the reactor vessel, internals and reactor coolant system and steam generators with-in the scope of license renewal that contain the piping, piping components and piping elements fabricated from copper alloy greater than 15% zinc exposed to closed cycle cooling water.Based on its review of the LRA, the staff confirmed that there are no copper alloy greater than 15% zinc piping, piping components, or piping elements exposed to closed cycle cooling water in the reactor vessel, internals and reactor coolant system and therefore, finds the applicant's determination acceptable. LRA Table 3.1.1, line item 57 addresses cast austenitic stainless steel class 1 piping, piping components, and piping elements and control rod drive pressure housings exposed to reactor coolant greater than 2500 C (greater than 4820 F). The GALL Report recommends the Thermal Aging Embrittlement of CASS AMP to manage loss of fracture toughness due to thermal aging embrittlement. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that with the exception of pump casings and valve bodies, there are no class 1 CASS piping, piping components, or piping elements in the reactor vessel, internals and reactor coolant system. Theapplicant also stated that the loss of fracture toughness due to thermal aging embrittlement in 3-155 this line item is not applicable because there are no steel piping, piping components, or piping elements exposed to closed cycle cooling water in the reactor vessel, internals and reactor coolant system. The staff reviewed LRA Sections 2.3.1 and 3.1 and confirmed that TMI-1 does not have support systems that are part of the reactor vessel, internals and reactor coolant system and steam generators within the scope of license renewal that contain the piping, piping . components and piping elements fabricated from steel exposed to closed cycle cooling water. Based on its review of the LRA, the staff confirmed that there are no steel piping, piping components, or piping elements exposed to closed cycle cooling water in the reactor vessel, internals and reactor coolant system and therefore, finds the applicant's determination acceptable. LRA Table 3.1.1, line item 54 addresses copper alloy piping, piping components, and piping elements exposed to closed cycle cooling water. The GALL Report recommends the Cycle Cooling Water System AMP to manage loss of material due to pitting, crevice, and galvanic corrosion in this component group. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that this line item is not applicable because there are no copper alloy piping, piping components, or piping elements exposed to closed cycle cooling water in the reactor vessel, internals and reactor coolant system. The staff reviewed LRA Sections 2.3.1 and 3.1 and confirmed that TMI-1 does not have support systems that are part of the reactor vessel, internals and reactor coolant system and steam generators with-in the scope of license renewal that contain the piping, piping components and piping elements fabricated from copper alloy exposed to closed cycle cooling water. Based on its review of the LRA, the staff confirmed that there are no steel piping, piping components, or piping elements exposed to closed cycle cooling water in the reactor vessel, internals and reactor coolant system and therefore, finds the applicant's determination acceptable. LRA Table 3.1.1, line item 56 addresses copper alloy greater than 15% zinc piping, piping components, and piping elements exposed to closed cycle cooling water. The GALL Report recommends the Selective Leaching of Materials AMP to manage loss of material due to selective leaching in this component group. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that this line item is not applicable because there are 'no copper alloy greater than 15% zinc piping, piping components, or piping elements exposed to closed cycle cooling water in the reactor vessel, internals and reactor coolant system. The staff reviewed LRA Sections 2.3.1 and 3.1 and confirmed that TMI-1 does not have support systems that are part of the reactor vessel, internals and reactor coolant system and steam generators with-in the scope of license renewal that contain the piping, piping components and piping elements fabricated from copper alloy greater than 15% zinc exposed to closed cycle cooling water. Based on its review of the LRA, the staff confirmed that there are no copper alloy greater than 15% zinc piping, piping components, or piping elements exposed to closed cycle cooling water in the reactor vessel, internals and reactor coolant system and therefore, finds the applicant's determination acceptable. LRA Table 3.1.1, line item 57 addresses cast austenitic stainless steel class 1 piping, piping components, and piping elements and control rod drive pressure housings exposed to reactor coolant greater than 250 0 C (greater than 482 0 F). The GALL Report recommends the'Thermal Aging Embrittlement of CASS AMP to manage loss of fracture toughness due to thermal aging embrittlement. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that with the exception of pump casings and valve bodies, there are no class 1 CASS piping, piping components, or piping elements in the reactor vessel, internals and reactor coolant system. The applicant also stated that the loss of fracture toughness due to thermal aging embrittlement in 3-155 class 1 CASS pump casings and valve bodies is addressed by Item 3.1.1-55. Based on its review of the LRA, the staff confirmed that with the exception of pump casings and valve bodies, there are no class 1 CASS piping, piping components, or piping elements in the reactor vessel, internals and reactor coolant system. Also, based on its review of the LRA, the staff confirmed that loss of fracture toughness due to thermal aging embrittlement in class 1 CASS pump casings and valve bodies is addressed by Item 3.1.1-55. The staff finds the applicant's determination acceptable. LRA Table 3.1.1, line item 60 addresses stainless steel flux thimble tubes (with or without chrome plating). The GALL Report recommends the Flux Thimble Tube Inspection AMP to manage loss of material due to wear. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that this line item is not applicable because it is applicable only to Westinghouse PWRs. Based on its review of the LRA and the GALL Report, the staff confirmed that this line item is only applicable to Westinghouse PWRs and also confirmed that TMI-1 is a Babcox and Wilcox PWR.The staff finds the applicant's determination acceptable. LRA Table 3.1.1, line item 63 addresses 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). The GALL Report recommends the Inservice Inspection (IWB, IWC, and IWD) AMP to manage loss of material due to wear. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that based on TMI-1 and industry operating experience,the loss of material due to wear is not predicted for this component, material, and environment combination in the reactor vessel, internals and reactor coolant system. Based on its review of the LRA, and the TMI-1 and industry operating experience, the staff confirmed that for TMI-1, the loss of material due to wear is not predicted for this component, material, and environment combination in the reactor vessel, internals and reactor coolant system, and finds the applicant's determination acceptable. LRA Table 3.1.1, line item 66 addresses steel steam generator secondary manways and handholds (cover only) exposed to air with leaking secondary-side water and/or steam. The GALL Report recommends the Inservice Inspection (IWB, IWC, and IWD) AMP for class 2 components to manage loss of material due to erosion. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that there are no steel steam generator secondary manways and handhold covers exposed to air with leaking secondary-side water and/or steam in the reactor vessel, internals and reactor coolant system. The staff reviewed LRA Sections 2.3.1 and 3.1 and confirmed that TMI-1 does not have support systems that are part of the reactor vessel, internals and reactor coolant system and steam generators with-in the scope of license renewal that contain the steel steam generator secondary manways and handhold covers fabricated from steel exposed to air with leaking secondary-side water and/or steam. Based on its review of the LRA, the staff confirmed that that there are no steel steam generator secondary manways and handhold covers exposed to air with leaking secondary-side water and/or steam in the reactor vessel, internals and reactor coolant system, and finds the applicant's determination acceptable. LRA Table 3.1.1, line item 67 addresses steel with stainless steel or nickel alloy cladding; or stainless steel pressurizer components exposed to reactor coolant. The GALL Report recommends the Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry AMPs to manage cracking due to cyclic loading. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that cracking due to cyclic loading in stainless steel or steel with stainless steel cladding reactor vessel, internals and reactor coolant system piping and components exposed to reactor coolant is addressed by Item 3.1.1-62. The applicant also stated that item 3.1.1-67 3-156 class 1 CASS pump casings and valve bodies is addressed by Item 3.1.1-55. Based on its review of the LRA, the staff confirmed that with the exception of pump casings and valve bodies, there are no class 1 CASS piping, piping components, or piping elements in the reactor vessel, internals and reactor coolant system. Also, based on its review of the LRA, the staff confirmed that loss of fracture toughness due to thermal aging embrittlement in class 1 CASS pump casings and valve bodies is addressed by Item 3.1.1-55. The staff finds the applicant's determination acceptable. LRA Table 3.1.1, line item 60 addresses stainless steel flux thimble tubes (with or without chrome plating). The GALL Report recommends the Flux Thimble Tube Inspection AMP to manage/oss of material due to wear, In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that this line item is not applicable because it is applicable only to Westinghouse PWRs. Based on its review of the LRA and the GALL Report, the staff confirmed that this line item is only applicable to Westinghouse PWRs and also confirmed that TMI-1 is a Babcox and Wilcox PWR. The staff finds the applicant's determination acceptable. LRA Table 3.1.1, line item 63 addresses 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). The GALL Report recommends the Inservice Inspection (IWB, IWC, and IWD) AMP to manage loss of material due to wear. In the applicant's response to AMR-GENERIC-2, the applicant stated that based on TMI-1 and industry operating experience, the loss of material due to wear is not predicted for this component, material, and environment combination in the reactor vessel, internals and reactor coolant system. Based on its review of the LRA, and the TMI-1 and industry operating experience, the staff confirmed that for TMI-1, the loss of material due to wear is not predicted for this component, material, and environment combination in the reactor vessel, internals and reactor coolant system, and finds the applicant's determination acceptable. LRA Table 3.1.1, line item 66 addresses steel steam generator secondary manways and hand holds (cover only) exposed to air with leaking secondary-side water and/or steam. The GALL Report recommends the Inservice Inspection (IWB, IWC, and IWD) AMP for class 2 components to manage loss of material due to erosion. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that there are no steel steam generator secondary manways and handhold covers exposed to air with leaking secondary-side water and/or steam in the reactor vessel, internals and reactor coolant system. The staff reviewed LRA Sections 2.3.1 and 3.1 and confirmed that TMI-1 does not have support systems that are part of the reactor vessel, internals and reactor coolant system and steam generators with-in the scope of license renewal that contain the steel steam generator secondary manways and handhold covers fabricated from steel exposed to air with leaking secondary-side water and/or steam. Based on its review of the LRA, the staff confirmed that that there are no steel steam generator secondary manways and handhold covers exposed to air with leaking secondary-side water and/or steam in the reactor vessel, internals and reactor coolant system, and finds the applicant's determination acceptable. LRA Table 3.1.1, line item 67 addresses steel with stainless steel or nickel alloy cladding; or stainless steel pressurizer components exposed to reactor coolant. The GALL Report recommends the Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry AMPs to manage cracking due to cyclic loading. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that cracking due to cyclic loading in stainless steel or steel with stainless steel cladding reactor vessel, internals and reactor coolant system piping and components exposed to reactor coolant is addressed by Item 3.1.1-62. The applicant also stated that item 3.1.1-67 3-156 identifies Water Chemistry as an additional aging management program; however, Water Chemistry is not an appropriate program for managing cracking due to cyclic loading. Based on its review of the LRA, the staff confirmed that cracking due to cyclic loading in stainless steel or steel with stainless steel cladding reactor vessel, internals and reactor coolant system piping and components exposed to reactor coolant is addressed by item 3.1.1-62, and also finds the applicant's Inservice Inspection Program adequate to manage cracking due to cyclic loading and therefore, finds the applicant's determination acceptable. LRA Table 3.1.1, line item 76 addresses steel steam generator tube support plate, tube bundle wrapper exposed to secondary feedwater/steam. The GALL Report recommends the Steam Generator Tube Integrity and Water Chemistry AMPs to manage loss of material due to erosion, general, pitting, and crevice corrosion, ligament cracking due to corrosion. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that there is no steel steam generator tube support plate, tube bundle wrapper exposed to secondary feedwater/steam in the reactor vessel, internals and reactor coolant system. The applicant also stated that the TMI-1 tube support plate is stainless steel. The applicant further stated that tube bundle wrappers are associated only with recirculating steam generators and that TMI-1 has once-through steam generators. Based on its review of the LRA, the staff confirmed that that TMI-1 has no steel steam generator tube support plate, tube bundle wrapper exposed to secondary feedwater/steam in the reactor vessel, internals and reactor coolant system and that the TMI-1 tube support plate is stainless steel. The staff also confirmed that tube bundle wrappers are associated only with recirculating steam generators and that TMI-1 has once-through steam generators. The staff finds the applicant's determination acceptable. LRA Table 3.1.1, line item 85 addresses nickel alloy piping, piping components, and piping elements exposed to air -indoor uncontrolled (external). The GALL Report indicates that there is no aging effect/mechanism and therefore, does not recommend an AMP. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that there are no nickel alloy piping, piping components, and piping elements exposed to air -indoor uncontrolled (external) in the reactor vessel, internals and reactor coolant system. The applicant stated that the external environment of nickel alloy piping, piping components, and piping elements in the reactor vessel, internals and reactor coolant system is air with borated water leakage. Based on its review of the LRA, the staff confirmed that there are no nickel alloy piping, piping components, and piping elements exposed to air -indoor uncontrolled (external) in the reactor vessel, internals and reactor coolant system. The staff also confirmed that the external environment of nickel alloy piping, piping components, and piping elements in the reactor vessel, internals and reactor coolant system is air with borated water leakage. The staff finds the applicant's determination acceptable. LRA Table 3.1.1, line item 87 addresses steel piping, piping components, and piping elements in concrete. The GALL Report indicates that there is no aging effect/mechanism and therefore, does not recommend an AMP. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that there are no steel piping, piping components, and piping elements exposed to concrete in the reactor vessel, internals and reactor coolant system. The staff reviewed LRA Sections 2.3.1 and 3.1 and confirmed that TMI-1 does not have support systems that are part of the reactor vessel, internals and reactor coolant system and steam generators with-in the scope of license renewal that contain the piping, piping components and piping elements fabricated from steel exposed to concrete. Based on its review of the LRA, the staff confirmed that there are no steel piping, piping components, and piping elements exposed to concrete in the reactor vessel, internals and reactor coolant system. The staff finds the applicant's determination acceptable. 3-157 identifies Water Chemistry as an additional aging management program; however, Water Chemistry is not an appropriate program for managing cracking due to cyclic loading. Based on its review of the LRA, the staff confirmed that cracking due to cyclic loading in stainless steel or steel with stainless steel cladding reactor vessel, internals and reactor coolant system piping and components exposed to reactor coolant is addressed by item 3.1.1-62, and also finds the applicant's Inservice Inspection Program adequate to manage cracking due to cyclic loading and therefore, finds the applicant's determination acceptable. ' LRA Table 3.1.1, line item 76 addresses steel steam generator tube support plate, tube bundle wrapper exposed to secondary feedwater/steam. The GALL Report recommends the Steam Generator Tube Integrity and Water Chemistry AMPs to manage loss of material due to erosion, general, pitting, and crevice corrosion, ligament cracking due to corrosion. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that there is no steel steam generator tube support plate, tube bundle wrapper exposed to secondary feedwater/steam in the reactor vessel, internals and reactor coolant system. The applicant also stated that the TMI-1 tube support plate is stainless steel. The applicant further stated that tube bundle wrappers are associated only with recirculating steam generators and that TMI-1 has once-through steam generators. Based on its review of the LRA, the staff confirmed that that TMI-1 has no steel steam generator tube support plate, tube bundle wrapper exposed to secondary feedwater/steam in the reactor vessel, internals and reactor coolant system and that the TMI-1 tube support plate is stainless steel. The staff also confirmed that tube bundle wrappers are associated only with recirculating steam generators and that TMI-1 has once-through steam generators. The staff finds the applicant's determination acceptable. LRA Table 3.1.1, line item 85 addresses nickel alloy piping, piping components, and piping elements exposed to air -indoor uncontrolled (external). The GALL Report indicates that there is no aging effecUmechanism and therefore, does not recommend an AMP. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that there are no nickel alloy piping, piping components, and piping elements exposed 'to air -indoor uncontrolled (external) in the reactor vessel, internals and reactor coolant system. The applicant stated that the external environment of nickel alloy piping, piping components, and piping elements in the reaCtor vessel, internals and reactor coolant system is air with borated water leakage. Based on its review of the LRA, the staff confirmed that there are no nickel alloy piping, piping components, and piping elements exposed to air -indoor uncontrolled (external) in the reactor vessel, internals and reactor coolant system. The staff also confirmed that the external environment of nickel alloy piping, piping components, and piping elements in the reactor vessel, internals and 'reactor coolant system is air with borated water leakage. The staff finds the applicant's determination acceptable. LRA Table 3.1.1, line item 87 addresses steel piping, piping components, and piping elements in concrete. The GALL Report indicates that there is no aging effecUmechanism and therefore, does not recommend an AMP. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that there are no steel piping, piping components, and piping elements exposed to concrete in the reactor vessel, internals and reactor coolant system. The staff reviewed LRA Sections 2.3.1 and 3.1 and confirmed that TMI-1 does not have support systems that are part of the reactor vessel, internals and reactor coolant system and steam generators with-in the scope of license renewal that contain the piping, piping components and piping elements fabricated from steel exposed to concrete. Based on its review of the LRA, the staff confirmed that there are no steel piping, piping components, and piping elements exposed to concrete in the reactor vessel, internals and reactor coolant system. The staff finds the applicant's determination acceptable. 3-157 3.1.2.1.2 Wall Thinning due to Flow-Accelerated Corrosion LRA Table 3.1.1, line item 3.1.1-59 addresses steel steam generator steam nozzle and safe ends;feedwater nozzle and safe ends; and auxiliary feedwater nozzles and safe ends exposed to secondary feedwater/steam. The GALL Report recommends the Flow Accelerated CorrosionAMP to manage wall thinning due to flow accelerated corrosion in this component group. The LRA states that this line item is not applicable because this component, material,environment, and aging effect/mechanism combination does not apply to the reactor vessel, internals, and reactor coolant systems. The staff noted that the applicant does have steel steam nozzles and safe ends in a treated water environment in the steam generator system as identified on page 3.1-131 of the LRA in Table 3.1.2-4. In addition, the staff noted that, LRA Table 3.0-1, defines treated water, and includes wet steam applications which are referenced as steam or secondary feedwater/steam in the GALL Report.In RAI AMR-Generic-2, dated January 5, 2009, the staff requested that the applicant provide additional information to justify why there are no aging effects requiring management for the component/material/environment combination identified above.In its response to the RAI dated January 12, 2009, the applicant stated that the feedwater andemergency feedwater nozzles are nickel-alloy and are not susceptible to flow accelerated corrosion and do not have safe ends. The applicant also stated that the main steam nozzles are low alloy steel and the main steam safe ends are carbon steel, however, flow accelerated corrosion is not predicted for these locations in the steam generator that are exposed to main steam because the main steam system by design is 35 degrees superheated and is therefore well above the optimum range for flow accelerated corrosion. Based on its review, the staff finds the response to the RAI acceptable because the feedwater and emergency feedwater nozzles are nickel-alloy, do not have safe ends, and are not susceptible to flow-accelerated corrosion. The staff reviewed EPRI guidelines NSAC-202L-R2, which is recommended in GALL AMP XI.M17, "Flow-Accelerated Corrosion," and determined that superheated steam systems regardless of temperature and pressure have a very low susceptibility to flow-accelerated corrosion and may be excluded from the Flow Accelerated Corrosion Program. The staff noted that the carbon steel main steam safe end locations in the steam generator are exposed to superheated steam and will have a very low susceptibility to flow-accelerated corrosion. The staff's concern described in RAI-AMR-Generic-2 for Item 3.1.1.59 is resolved.3.1.2.1.3 Cracking due to Stress Corrosion Cracking (SCC), Thermal and Mechanical Loading LRA Table 3.1.1, line item 3.1.1-70 addresses stainless steel and steel with stainless steel cladding class 1 piping, fittings and branch connections less than NPS 4 exposed to reactor coolant. The GALL report recommends the Inservice Inspection (IWB, IWC, and IWD), Water Chemistry, and One-Time Inspection of ASME Code Class 1 Small-bore Piping AMPS to manage cracking due to stress corrosion cracking, thermal and mechanical loading in this component group.The applicant credits the ASME Section Xl Inservice Inspection, Subsections IWB, IWC, and IWD Program, and the Water Chemistry Program to manage cracking due to stress corrosion cracking in the stainless steel class 1 piping, fittings, and branch connections less than NPS 4 exposed to reactor coolant and treated water. 3-158 3.1.2.1.2 Wall Thinning due to Flow-Accelerated Corrosion lRA Table 3.1.1, line item 3.1.1-59 addresses steel steam generator steam nozzle and safe ends; feedwater nozzle and safe ends; and auxiliary feedwater nozzles and safe ends exposed to secondary feedwaterlsteam. The GALL Report recommends the Flow Accelerated Corrosion AMP to manage wall thinning due to flow accelerated corrosion in this component group. The LRA states that this line item is not applicable because this component, material, environment, and aging effectlmechanism combination does not apply to the reactor vessel, internals, and reactor coolant systems. The staff noted that the applicant does have steel steam nozzles and safe ends in a treated water environment in the steam generator system as identified on page 3.1-131 of the LRA in Table 3.1.2-4. In addition, the staff noted that, lRA Table 3.0-1, defines treated water, and includes wet steam applications which are referenced as steam or secondary feedwaterlsteam in the GAll Report. In RAI AMR-Generic-2, dated January 5, 2009, the staff requested that the applicant provide additional information to justify why there are no aging effects requiring management for the componentlmateriallenvironmentcombination identified above. In its response to the RAI dated January 12, 2009, the applicant stated that the feedwater and emergency feedwater nozzles are nickel-alloy and are not susceptible to flow accelerated corrosion and do not have safe ends. The applicant also stated that the main steam nozzles are low alloy steel and the main steam safe ends are carbon steel, however, flow accelerated corrosion is not predicted for these locations in the steam generator that are exposed to main steam because the main steam system by design is 35 degrees superheated and is therefore well above the optimum range for flow accelerated corrosion. Based on its review, the staff finds the response to the RAI acceptable because the feedwater and emergency feedwater nozzles are nickel-alloy, do not have safe ends, and are not susceptible to flow-accelerated corrosion. The staff reviewed EPRI guidelines NSAC-202l-R2, which is recommended in GALL AMP XI.M17, "Flow-Accelerated Corrosion," and determined that superheated steam systems regardless of temperature and pressure have a very low susceptibility to flow-accelerated corrosion and may be excluded from the Flow Accelerated Corrosion Program. The staff noted that the carbon steel main steam safe end locations in the steam generator are exposed to superheated steam and will have a very low susceptibility to accelerated corrosion. The staff's concern described in RAI-AMR-Generic-2 for Item 3.1.1.59 is resolved. 3.1.2.1.3 Cracking due to Stress Corrosion Cracking (SCC), Thermal and Mechanical loading lRA Table 3.1.1, line item 3.1.1-70 addresses stainless steel and steel with stainless steel cladding class 1 piping, fittings and branch connections less than NPS 4 exposed to reactor coolant. The GALL report recommends the Inservice Inspection (IWB, IWC, and IWD), Water Chemistry, and One-Time Inspection of ASME Code Class 1 Small-bore Piping AMPS to manage cracking due to stress corrosion cracking, thermal and mechanical loading in this component group. The applicant credits the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program, and the Water Chemistry Program to manage cracking due to stress corrosion cracking in the stainless steel class 1 piping, fittings, and branch connections less than NPS 4 exposed to reactor coolant and treated water. 3-158 The SRP-LR recommends implementation of the Inservice Inspection (IWB, IWC, and IWD), Water Chemistry, and One-Time Inspection of ASME Code Class 1 Small-bore Piping Programs to manage cracking in small-bore piping. The applicant stated in the discussion column of Item 3.1.1-70, that since cracking has been discovered in small bore piping, the periodic examination activities of ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program, are credited with aging management of class 1 small-bore piping in lieu of GALL AMP XI.M35, "One Time Inspection of ASME Code Class 1 Small-Bore Piping." In GALL AMP XI.M35 the "monitoring and trending" element recommends evaluation of inspection results to determine if additional examinations are needed and recommends that additional inspections should be performed at a sufficient number of locations to assure an adequate sample size. The staff noted that the LRA does not provide the details of methods used to detect cracking of small bore piping (including inspection and evaluation methods, inspection scope and frequency). In RAI 3.1.1-1, dated October 16, 2008, the staff requested that the applicant provide additional information regarding the activities used to detect degradation of small bore piping.In its response to the RAI dated November 12, 2008, the applicant stated that Risk Informed ISI was/will be used to select socket welds for VT-2 examination and small-bore butt welds for ultrasonic and penetrant testing during the current third ten-year inspection interval. The staff noted that although welds selected for inspection are based on the RISI program, it is not clear if small-bore welds specific to the RCS and Core Flooding System will be subject to inspection such that the intent of the GALL AMP XI.M35 "monitoring and trending" element is met.In RAI 3.1.1-2, dated January 5, 2009, the staff requested the applicant provide additionalinformation indicating which small bore piping welds of the RCS and core flooding system receive volumetric or VT-2 inspection and to identify inspections and a schedule for welds in small bore piping where cracking has been discovered. In its response to the RAI dated January 12, 2009, the applicant stated that risk informed methods are used to select RCS piping welds for inspection including small bore piping locations. The applicant also stated that "High" risk category small bore piping butt welds in the RCS have received volumetric inspection on a routine basis since a fatigue crack was discovered in the 2" cold leg drain line off the B cold leg reactor coolant piping in 1995. The applicant stated that volumetric examination of 2 11/2 inch high pressure injection/makeup line butt welds were performed on one weld in 2005 and eight welds in 2007 with acceptable results. The applicant stated that no additional cracking was identified during inspections after the fatigue crack wasdiscovered and that inspections of the replacement weld of the 2" cold leg drain line off the B cold leg reactor coolant piping were performed in 2001 (volumetric) and in 2003 (penetrant) with acceptable results. The applicant stated that inspection of corresponding weld off the D cold leg drain line was performed in 2003 (penetrant) with acceptable results and cold leg drain line welds A, B, and D are scheduled for bare metal visual and volumetric inspections in the Fall of 2009.Based on its review, the staff finds the response to the RAIs acceptable because the inspections of ASME Code Class 1 small-bore piping which are implemented through the applicant's ISI program meets the applicable program elements of GALL AMP XI.M35. The staff noted that piping less than or equal to NPS 4 received volumetric inspection, that cracking was detected in ASME Code Class 1 small-bore piping, and that additional inspections have been performed and will be performed in the future consistent with ASME Section XI, Subsection IWB at a sufficient number of locations based on risk-informed ISI and augmented inspection at the 2" cold leg drain lines where cracking was discovered. The staff finds management of cracking in ASME Code 3-159 The SRP-LR recommends implementation of the Inservice Inspection (IWB, IWC, and IWD), Water Chemistry, and One-Time Inspection of ASME Code Class 1 Small-bore Piping Programs to manage cracking in small-bore piping. The applicant stated in the discussion column of Item 3.1.1-70, that since cracking has been discovered in small bore piping, the periodic examination activities of ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program, are credited with aging management of class 1 small-bore piping in lieu of GALL AMP XI.M35, "One Time Inspection of ASME Code Class 1 Small-Bore Piping." In GALL AMP XI.M35 the "monitoring and trending" element recommends evaluation of inspection results to determine if additional examinations are needed and recommends that additional inspections should be performed at a sufficient number of locations to assure an adequate sample size. The staff noted that the LRA does not provide the details of methods used to detect cracking of small bore piping (including inspection and evaluation methods, inspection scope and frequency). In RAI 3.1.1-1, dated October 16, 2008, the staff requested that the applicant provide additional information regarding the activities used to detect degradation of small bore piping. In its response to the RAI dated November 12, 2008, the applicant stated that Risk Informed lSI was/will be used to select socket welds for VT-2 examination and small-bore butt welds for ultrasonic and penetrant testing during the current third ten-year inspection interval. The staff noted that although welds selected for inspection are based on the RISI program, it is not clear if small-bore welds specific to the RCS and Core Flooding System will be subject to inspection such that the intent of the GALL AMP XI.M35 "monitoring and trending" element is met. In RAI3.1.1-2, dated January 5,2009, the staff requested the applicant provide additional information indicating which small bore piping welds of the RCS and core flooding system receive volumetric or VT-2 inspection and to identify inspections and a schedule for welds in small bore piping where cracking has been discovered. In its response to the RAI dated January 12, 2009, the applicant stated that risk informed methods are used to select RCS piping welds for inspection including small bore piping locations. The applicant also stated that "High" risk category small bore piping butt welds in the RCS have received volumetric inspection on a routine basis since a fatigue crack was discovered in the 2" cold leg drain line off the B cold leg reactor coolant piping in 1995. The applicant stated that volumetric examination of 2 inch high pressure injection/makeup line butt welds were performed on one weld in 2005 and eight welds in 2007 with acceptable results. The applicant stated that no additional cracking was identified during inspections after the fatigue crack was discovered and that inspections of the replacement weld of the 2" cold leg drain line off the B cold leg reactor coolant piping were performed in 2001 (volumetric) and in 2003 (penetrant) with acceptable results. The applicant stated that inspection of corresponding weld off the D cold leg drain line was performed in 2003 (penetrant) with acceptable results and cold leg drain line welds A, B, and 0 are scheduled for bare metal visual and volumetric inspections in the Fall of 2009. Based on its review, the staff finds the response to the RAls acceptable because the inspections of ASME Code Class 1 small-bore piping which are implemented through the applicant's lSI program meets the applicable program elements of GALL AMP XI.M35. The staff noted that piping less than or equal to NPS 4 received volumetric inspection, that cracking was detected in ASME Code Class 1 small-bore piping, and that additional inspections have been performed and will be performed in the future consistent with ASME Section XI, Subsection IWB at a sufficient number of locations based on risk-informed lSI and augmented inspection at the 2" cold leg drain lines where cracking was discovered, The staff finds management of cracking in ASME Code 3-159 Class 1 small bore piping using the applicant's AMPs acceptable. The staff's concerns described in RAI 3.1.1-1 and 3.1.1-2 are resolved.3.1.2.1.4 Conclusion for AMRs Consistent with the GALL Report The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing the associated aging effects. On the basis of its review, the staff concludes that the AMR results, which the applicant claimed to be consistent with the GALL Report, are consistent with the GALL Report AMRs. Therefore, the staff concludes that the applicant has demonstrated that the aging effects for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).3.1.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended LRA Section 3.1.2.2 provides further evaluation of aging management as recommended by the GALL Report for the RCS components. The applicant provided information concerning how it will manage the following aging effects:* Cumulative Fatigue Damage* Loss of Material due to General, Pitting, And Crevice Corrosion" Loss of Fracture Toughness due to Neutron Irradiation Embrittlement

  • Cracking due to Stress Corrosion Cracking (SCC) and Intergranular Stress Corrosion Cracking* 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 Irradiated-Assisted SCC (IASCC)* Cracking due to Primary Water Stress Corrosion Cracking (PWSCC)* Wall Thinning due to Flow Accelerated Corrosion (FAC)3-160 Class 1 small bore piping using the applicant's AMPs acceptable.

The staff's concerns described in RAI 3.1.1-1 and 3.1.1-2 are resolved. 3.1.2.1.4 Conclusion for AMRs Consistent with the GALL Report The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing the associated aging effects. On the basis of its review, the staff concludes that the AMR results, which the applicant claimed to be consistent with the GALL Report, are consistent with the GALL Report AMRs. Therefore, the staff concludes that the. applicant has demonstrated that the aging effects for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). 3.1.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended LRA Section 3.1.2.2 provides further evaluation of aging management as recommended by the GALL Report for the RCS components. The applicant provided information concerning how it will manage the following aging effects:

  • Cumulative Fatigue Damage
  • Loss of Material due to General, Pitting, And Crevice Corrosion
  • Loss of Fracture Toughness due to Neutron Irradiation Embrittlement
  • Cracking due to Stress Corrosion Cracking (SCC) and Intergranular Stress Corrosion Cracking
  • 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 Irradiated-Assisted SCC (IASCC)
  • Cracking due to Primary Water Stress Corrosion Cracking (PWSCC)
  • Wall Thinning due to Flow Accelerated Corrosion (FAC) 3-160 0 Changes in Dimensions due to Void Swelling* Cracking due to SCC and PWSCC* Cracking due to SCC, PWSCC, and IASCC 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 applicant's evaluation. The staff determined whether the applicant adequately addressed the issues for which furtherevaluation is recommended.

The staff reviewed the applicant's further evaluations against the criteria contained in SRP-LR Section 3.1.2.2. The staff's review of the applicant's further evaluation follows.3.1.2.2.1 Cumulative Fatigue Damage LRA Section 3.1.2.2.1 states that fatigue is a TLAA, as defined in 10 CFR 54.3, which must be evaluated in accordance with 10 CFR 54.21(c)(1). LRA Table 3.1.1 identifies AMR Lines 3.1.1-1 and 3.1.1-5 through 3.1.1-10 as TLAA items for the reactor coolant system, the reactor vessel, the reactor vessel internals, and the steam generator. The applicant performed cumulative fatigue evaluations for these components. SER Section 4.3 documents the staffs review of the applicant's evaluation of TLAA for these components. LRA Table 3.1.1, line items 2 -4, discusses the applicant's determination on GALL AMR line items that are applicable only to BWR-designed reactors. In the applicant AMR discussions for line items 2 -4, the applicant indicates that these line items are applicable to BWRs only and are not used for TMI-1. The staff confirmed that AMR line items 2 -4, in Table 1 of the GALL Report, Volume 1 are only applicable to BWR designed reactors, and that TMI-1 is a pressurized water reactor with a dry ambient containment. Based on this determination, the staff finds that AMR line items 2 -4, in Table 1 of the GALL Report, Volume 1 are not applicable to TMI-i.SRP-LR Section 3.1.2.2.1 states that fatigue is a time-limited aging analysis (TLAA) as defined in 10 CFR 54.3 and TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c)(1). The SRP-LR also states that this TLAA is addressed separately in Section 4.3, of the SRP-LR.For PWRs 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 I 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. Based on a review of the programs identified above, the staff concludes that the applicant's 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 theintended functions will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 3-161* Changes in Dimensions due to Void Swelling

  • Cracking due to SCC and PWSCC
  • Cracking due to SCC, PWSCC, and IASCC 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 applicant's evaluation.

The staff determined whether the applicant adequately addressed the issues for which further. evaluation is recommended. The staff reviewed the applicant's further evaluations against the criteria contained in SRP-LR Section 3.1.2.2. The staff's review of the applicant's further evaluation follows. 3.1.2.2.1 Cumulative Fatigue Damage LRA Section 3.1.2.2.1 states that fatigue is a TLAA, as defined in 10 CFR 54.3, which must be evaluated in accordance with 10 CFR 54.21(c)(1). LRA Table 3.1.1 identifies AMR Lines 3.1.1-1 and 3.1.1-5 through 3.1.1-10 as TLAA items for the reactor coolant system, the reactor vessel, the reactor vessel internals, and the steam generator. The applicant performed cumulative fatigue evaluations for these components. SER Section 4.3 documents the staff's review of the applicant's evaluation of TLAA for these components. LRA Table 3.1.1, line items 2 -4, discusses the applicant's determination on GALL AMR line items that are appficable only to BWR-designed reactors. In the applicant AMR discussions for line items 2 -4, the applicant indicates that these line items are applicable to BWRs only and are not used for TMI-1. The staff confirmed that AMR line items 2 -4, in Table 1 of the GALL Report, Volume 1 are only applicable to BWR designed reactors, and that TMI-1 is a pressurized water reactor with a dry ambient containment. Based on this determination, the staff finds that AMR line items 2 -4, in Table 1 of the GALL Report, Volume 1 are not applicable to TMI-1. SRP-LR Section 3.1.2.2.1 states that fatigue is a time-limited aging analysis (TLAA) as defined in 10 CFR 54.3 and TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c)(1). The SRP-LR also states that this TLAA is addressed separately in Section 4.3, of the SRP-LR. For PWRs 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. . Based on a review of the programs identified above, the staff concludes that the applicant's 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). 3-161 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 3.1.2.2.2.1 addresses loss of material due to general, pitting, and crevice corrosion in the steel steam generator shell assembly, the steel top head enclosure, and top head nozzles exposed to reactor coolant. The applicant stated that a One-Time Inspection Program will be implemented for susceptible locations to verify effectiveness of the Water Chemistry Program to manage loss of material due to general, pitting, and crevice corrosion in this component group which also includes steam generator level sensing and drain connections, main steam nozzle and safe ends, primary manway and inspection port covers, secondary manway and hand hole covers, and upper and lower tube sheets exposed to treated water and reactor coolant in the steam generator. The staff reviewed LRA Section 3.1.2.2.2.1 against the criteria in SRP-LR Section 3.1.2.2.2.1, which states that loss of material due to general, pitting, and crevice corrosion could occur in the steel PWR steam generator shell assembly exposed to secondary feedwater and steam. The SRP-LR states that loss of material due to general, pitting, and crevice corrosion could also occur for the steel top head enclosure (without cladding) top head nozzles [vent, top head spray or reactor core isolation cooling (RCIC), and spare]exposed to reactor coolant, and the existing program relies on control of reactor water chemistry to mitigate corrosion, but that control of water chemistry does not preclude loss of material due to pitting and crevice corrosion at locations of stagnant flow conditions; therefore, effectiveness of the water chemistry control program should be confirmed to ensure that corrosion is not occurring. The GALL Report recommends further evaluation of programs to verify effectiveness of the water chemistry control program. The SRP-LR states that one-time inspection of select components at susceptible locations is an acceptable method to determine whether an aging effect is not occurring or an aging effect is progressing very slowly such that the component's intended function will be maintained during the period of extended operation. The staff reviewed the applicant's Water Chemistry program. The staffs evaluation of this program, which is documented in SER Section 3.0.3.2.2, found that the Water Chemistry program, with an enhancement, is consistent with GALL AMP XI.M2, "Water Chemistry," and provides mitigation for loss of material due to general, pitting and crevice corrosion.The staff reviewed the applicant's One-Time Inspection program. The staffs evaluation of this program, which is documented in SER Section 3.0.3.2.14, found that the One-Time Inspection program is consistent with the GALL AMP XI.M32, "One-Time Inspection," and is adequate to detect the presence or note the absence of loss of material due to general, pitting or crevice corrosion at susceptible locations for components within the scope of the program. Based on the staff's determination that the Water Chemistry program provides mitigation and the One-Time Inspection program provides detection for the aging effect of loss of material due to general, pitting or crevice corrosion, the staff finds the applicant's proposed AMPs for managing the aging effect of loss of material due to general, pitting or crevice corrosion in the steel steam generator shell assembly to be acceptable. (2) LRA Sections 3.1.2.2.2.2 through 3.1.2.2.2.4 refer to LRA Table 3.1.1, line items 11, and 13 -15 that discuss the applicant's determination on GALL AMR line items that are applicable only to BWR-designed reactors. In the applicant AMR discussions for line items 11, and 13 -15, the applicant indicates that these line items are applicable to BWRs only and are not used for TMI-1. The staff confirmed that AMR line items 11 and 13 -15, in 3-162 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 3.1.2.2.2.1 addresses loss of material due to general, pitting, and crevice corrosion in the steel steam generator shell assembly, the steel top head enclosure, and top head nozzles exposed to reactor coolant. The applicant stated that a One-Time Inspection Program will be implemented for susceptible locations to verify effectiveness of the Water Chemistry Program to manage loss of material due to general, pitting, and crevice corrosion in this component group which also includes steam generator level sensing and drain connections, main steam nozzle and safe ends, primary manway and inspection port covers, secondary manway and hand hole covers, and upper and lower tube sheets exposed to treated water and reactor coolant in the steam generator. The staff reviewed LRA Section 3.1.2.2.2.1 against the criteria in SRP-LR Section 3.1.2.2.2.1, which states that loss of material due to general, pitting, and crevice corrosion could occur in the steel PWR steam generator shell assembly exposed to secondary feedwater and steam. The SRP-LR states that loss of material due to general, pitting, and crevice corrosion could also occur for the steel top head enclosure (without cladding) top head nozzles [vent, top head spray or reactor core isolation cooling (RCIC), and spare] exposed to reactor coolant, and the existing program relies on control of reactor water chemistry to mitigate corrosion, but that control of water chemistry does not preclude loss of material due to pitting and crevice corrosion at locations of stagnant flow conditions; therefore, effectiveness of the water chemistry control program should be confirmed to ensure that corrosion is not occurring. The GALL Report recommends further evaluation of programs to verify effectiveness of the water chemistry control program. The SRP-LR states that one-time inspection of select components at susceptible locations is an acceptable method to determine whether an aging effect is not occurring or an aging effect is progressing very slowly such that the component's intended function will be maintained during the period of extended operation. The staff reviewed the applicant's Water Chemistry program. The staff's evaluation of this program, which is documented in SER Section 3.0.3.2.2, found that the Water Chemistry program, with an enhancement, is consistent with GALL AMP XI.M2, "Water Chemistry," and provides mitigation for loss of material due to general, pitting and crevice corrosion. The staff reviewed the applicant's One-Time Inspection program. The staff's evaluation of this program, which is documented in SER Section found that the One-Time Inspection program is consistent with the GALL AMP XI.M32, "One-Time Inspection," and is adequate to detect the presence or note the absence of loss of material due to general, pitting or crevice corrosion at susceptible locations for components within the scope of the program. Based on the staff's determination that the Water Chemistry program provides mitigation and the One-Time Inspection program provides detection for the aging effect of loss of material due to general, pitting or crevice corrosion, the staff finds the applicant's proposed AMPs for managing the aging effect of loss of material due to general, pitting or crevice corrosion in the steel steam generator shell assembly to be acceptable. (2) LRA Sections 3.1.2.2.2.2 through 3.1.2.2.2.4 refer to LRA Table 3.1.1, line items 11, and 13 -15 that discuss the applicant's determination on GALL AMR line items that are applicable only to BWR-designed reactors. In the applicant AMR discussions for line items 11, and 13 -15, the applicant indicates that these line items are applicable to BWRs only and are not used for TMI-1. The staff confirmed that AMR line items 11 and 13 -15, in 3-162 Table 1 of the GALL Report, Volume 1 are only applicable to BWR designed reactors, and that TMI-1 is a pressurized water reactor with a dry ambient containment. Based on thisdetermination, the staff finds that the applicant has provided an acceptable basis for concluding that AMR line items 11 and 13 -15, in Table 1 of the GALL Report, Volume 1 are not applicable to TMI-I.(3) LRA Table 3.1.1, line item 16 addresses steel steam generator upper and lower shell and transition cone exposed to secondary feedwater and steam and discusses the applicant's determination on a GALL AMR line item that is applicable only to recirculating steam generators. The staff confirmed that AMR line item 16, in Table 1 of the GALL Report, Volume 1 is only applicable to recirculating steam generators and confirmed by reviewing various sections of the LRA, that TMI-1 has once through steam generators. Based on this determination, the staff finds that AMR line item 16, in Table 1 of the GALL Report, Volume 1 is not applicable to TMI-I.Based on a review of the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.2 criteria. For those line items that apply to LRA Section 3.1.2.2.2, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.2.2.3 Loss of Fracture Toughness due to Neutron Irradiation Embrittlement The staff reviewed LRA Section 3.1.2.2.3 against the following criteria in SRP-LR Section 3.1.2.2.3: (1) LRA Section 3.1.2.2.3 states that neutron irradiation embrittlement is a TLAA, as defined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.2 documents the staff's review of the applicant's evaluation of this TLAA.(2) LRA Section 3.1.2.2.3 addresses loss of fracture toughness due to neutron irradiation embrittlement. The applicant stated that participation in the MIRVSP, as described in B.2.1.17, manages this aging effect in low alloy steel components clad with stainless steel exposed to reactor coolant and neutron flux.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 plates, forgings, 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 factors 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 applicant's reactor vessel surveillance program is documented in LRA Appendix B, Reactor Vessel Surveillance (B.2.1.17) and Section 4.2. The TMI-1 surveillance material contained in Capsule TMI2-LG2 was tested to meet the requirements of ASTM Standard 3-163 Table 1 of the GALL Report, Volume 1 are only applicable to BWR designed reactors, and that TMI-1 is a pressurized water reactor with a dry ambient containment. Based on this determination, the staff finds that the applicant has provided an acceptable basis for concluding that AMR line items 11 and 13 -15, in Table 1 of the GALL Report, Volume 1 are not applicable to TMI-1. (3) LRA Table 3.1.1, line item 16 addresses steel steam generator upper and lower shell and transition cone exposed to secondary feedwater and steam and discusses the applicant's determination on a GALL AMR line item that is applicable only to recirculating steam generators. The staff confirmed that AMR line item 16, in Table 1 of the GALL Report, Volume 1 is only applicable to recirculating steam generators and confirmed by reviewing various sections of the LRA, that TMI-1 has once through steam generators. Based on this determination, the staff finds that AMR line item 16, in Table 1 of the GALL Report, Volume 1 is not applicable to TMI-1. Based on a review of the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.2 criteria. For those line items that apply to LRA Section 3.1.2.2.2, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21 (a)(3). 3.1.2.2.3 Loss of Fracture Toughness due to Neutron Irradiation Embrittlement The staff reviewed LRA Section 3.1.2.2.3 against the following criteria in SRP-LR Section 3.1.2.2.3: (1 ) LRA Section 3.1.2.2.3 states that neutron irradiation embrittlement is a TLAA, as defined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.2 documents the staff's review of the applicant'S evaluation of this TLAA. LRA Section 3.1.2.2.3 addresses loss of fracture toughness due to neutron irradiation embrittlement. The applicant stated that participation in the MIRVSP, as described in 8.2.1.17, manages this aging effect in low alloy steel components clad with stainless steel exposed to reactor coolant and neutron flux. 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 plates, forgings, 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 factors 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 applicant's reactor vessel surveillance program is documented in LRA Appendix B, Reactor Vessel Surveillance (B.2.1.17) and Section 4.2. The TMI-1 surveillance material contained in Capsule TMI2-LG2 was tested to meet the requirements of ASTM Standard 3-163 E 185-82. By letter dated November 17, 2003 (ML033220292), the staff reviewed BAW-2439, "Babcock & Wilcox Owners Group Analysis of Capsule TMI2-LG2: Master Integrated Reactor Vessel Surveillance Program." The wetted surface fluence values projected for 52 EFPY ranged from 1.177 x 1019 n/cm 2 to 1.971 x 1019 n/cm 2 (E > 1 MeV)for the TMI-1 beltline materials. Specimens from the TMI2-LG2 capsule received an average fast neutron fluence of 2.01 x 1019 n/cm 2 (E > 1 MeV). This meets the ASTM Standard E 185-82 criterion which states that capsules may be removed when the capsule neutron fluence is between one and two times the limiting fluence calculated for the vessel at the expected EOL. The surveillance specimens in the last capsule removed, Capsule TMI2-LG2, were exposed to fluences equivalent to approximately 60 years (52 EFPY) of vessel operation. Based on the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.3 criteria. For those line items that apply to LRA Section 3.1.2.2.3, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21 (a)(3).3.1.2.2.4 Cracking due to SCC and IGSCC 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), stating that this aging effect is not applicable to TMI-1 which is a PWR.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 TMI-1 because TMI-1 is a PWR, 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, stating that this aging effect is not applicable to TMI-1 which is a PWR.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 TMI-1 because TMI-1 is a PWR, and the staff guidance in this SRP-LR section is only applicable to BWR-designed reactors.Based on the above, the staff concludes that the staff's guidance criteria of SRP-LR Section 3.1.2.2.4, Items (1) and (2) do not apply to TMI-1 because the guidance is applicable to BWR-designed reactors and TMI-1 is a PWR.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. 3-164 E 185-82. By letter dated November 17, 2003 (ML033220292), the staff reviewed BAW-2439, "Babcock & Wilcox Owners Group Analysis of Capsule TMI2-LG2: Master Integrated Reactor Vessel Surveillance Program." The wetted surface fluence values projected for 52 EFPY ranged from 1.177 x 10 19 n/cm 2 to 1.971 x 10 19 n/cm 2 (E > 1 MeV) for the,TMI-1 beltline materials. Specimens from the TMI2-LG2 capsule received an average fast neutron fluence of 2.01 x 10 19 n/cm 2 (E > 1 MeV). This meets the ASTM Standard E 185-82 criterion which states that capsules may be removed when the capsule neutron fluence is between one and two times the limiting fluence calculated for the vessel at the expected EOL. The surveillance specimens in the last capsule removed, Capsule TMI2-LG2, were exposed to fluences equivalent to approximately 60 years (52 EFPY) of vessel operation. Based on the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.3 criteria. For those line items that apply to LRA Section 3.1.2.2.3, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 eFR 54.21 (a)(3). 3.1.2.2.4 Cracking due to SCC and IGSCC 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 sec and intergranular SCC (IGSeC), stating that this aging effect is not applicable to TMI-1 which is a PWR. SRP-LR Section 3.1.2.2.4 states that cracking due to SCC and IGSCe 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 TMI-1 because TMI-1 is a PWR, and the staff guidance in this SRP-LR section is only applicable to designed reactors. (2) LRA Section 3.1.2.2.4 addresses cracking due to SCC and IGSCC, stating that this aging effect is not applicable to TMI-1 which is a PWR. SRP-LR Section 3.1.2.2.4 states that cracking due to SCC and IGSCe 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 TMI-1 because TMI-1 is a PWR, and the staff guidance in this SRP-LR section is only applicable to designed reactors. Based on the above, the staff concludes that the staff's guidance criteria of SRP-LR Section 3.1.2.2.4, Items (1) and (2) do not apply to TMI-1 because the guidance is applicable to BWR-designed reactors and TMI-1 is a PWR. 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. 3-164 In LRA Section 3.1.2.2.5, the applicant states that crack growth due to cyclic loading (underclad cracking) is a TLAA as defined in 10 CFR 54.3, which must be evaluated in accordance with 10 CFR 54.21(c)(1). The applicant performed fatigue crack growth and fracture toughness evaluations. SER Section 4.3 documents the staff's review of the applicant's evaluation of this TLAA.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).3.1.2.2.6 Loss of Fracture Toughness due to Neutron Irradiation Embrittlement and Void Swelling The staff reviewed LRA Section 3.1.2.2.6 against the criteria in SRP-LR Section 3.1.2.2.6. LRA Section 3.1.2.2.6 addresses loss of fracture toughness due to neutron irradiation embrittlement and void swelling in stainless steel and nickel alloy reactor vessel internal components exposed to reactor coolant and neutron flux. The applicant stated a commitment related to reactor vessel internals to: (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval. The applicant documented this commitment in LRA Appendix A, Section A.5, Commitment No. 36.The staff reviewed LRA Section 3.1.2.2.6 against the criteria in SRP-LR Section 3.1.2.2.6, which states that loss of fracture of toughness due to neutron irradiation embrittlement and void swelling may occur in stainless steel and nickel alloy reactor vessel internal components exposed to reactor coolant and neutron flux. The GALL Report recommends no further aging management review if the applicant provides a commitment in the UFSAR Supplement to (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3)upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval.The staff noted that the applicant's commitment stated in LRA Appendix A, Section A.5, is consistent with the commitment described in SRP-LR Section 3.1.2.2.6. The staff also noted that all of the AMR results lines that refer to LRA Table 3.1.1, item 3.1.1-22, are aligned with the applicant's commitment for inspection of reactor vessel internals. On the basis that the applicant provides the appropriate commitment in the UFSAR Supplement and applicable AMR results are appropriately aligned with that commitment, the staff finds the applicant's AMR results for stainless steel, nickel alloy, and cast austenitic stainless steel (CASS) reactor vessel internal 3-165 In LRA Section 3.1.2.2.5, the applicant states that crack growth due to cyclic loading (underclad cracking) is a TLAA as defined in 10 CFR 54.3, which must be evaluated in accordance with 10 CFR 54.21(c)(1). The applicant performed fatigue crack growth and fracture toughness evaluations. SER Section 4.3 documents the staffs review of the applicant's evaluation of this TLAA. 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-CI 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). 3.1.2.2.6 Loss of Fracture Toughness due to Neutron Irradiation Embritllement 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 embritllement and void swelling in stainless steel and nickel alloy reactor vessel internal components exposed to reactor coolant and neutron flux. The applicant stated a commitment related to reactor vessel internals to: (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval. The applicant documented this commitment in LRA Appendix A,Section A.5, Commitment No. 36. The staff reviewed LRA Section 3.1.2.2.6 against the criteria in SRP-LR Section 3.1.2.2.6, which states that loss of fracture of toughness due to neutron irradiation embrittlement and void swelling may occur in stainless steel and nickel alloy reactor vessel internal components exposed to reactor coolant and neutron flux. The GALL Report recommends no further aging management review if the applicant provides a commitment in the UFSAR Supplement to (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval. The staff noted that the applicant's commitment stated in LRA Appendix A, Section A.5, is consistent with the commitment described in SRP-LR Section 3.1.2.2.6. The staff also noted that all of the AMR results lines that refer to LRA Table 3.1.1, item 3.1.1-22, are aligned with the applicant's commitment for inspection of reactor vessel internals. On the basis that the applicant provides the appropriate commitment in the UFSAR Supplement and applicable AMR results are appropriately aligned with that commitment, the staff finds the applicant's AMR results for stainless steel, nickel alloy, and cast austenitic stainless steel (CASS) reactor vessel internal 3-165 components exposed to reactor coolant and neutron flux, with an aging effect of loss of fracture toughness due to neutron irradiation embrittlement and void swelling to be acceptable. Based on a review of the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.6 criteria. For those line items that apply to LRA Section 3.1.2.2.6, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21 (a)(3).3.1.2.2.7 Cracking due to SCC 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 reactor vessel closure head flange leak detection line and bottom-mounted instrument guide tubes. The applicant stated that this component, material, environment, and aging effect/mechanism does not apply in the reactor vessel, internals, and reactor coolant system. The GALL Report recommends a plant specific AMP to manage cracking due to SCC in this component group. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that this line item is not applicable because the components are included with the reactor vessel system, class 1 piping, fittings and branch connections less than NPS 4".The applicant also stated that the components are stainless steel with an external environment of air with borated water leakage and an internal environment of reactor coolant and the AMR results for these components are included in LRA Table 3.1.2-2, and are shown on pages 3.1-74 and 3.1-75 of the LRA. The applicant also refers to its response to RAI 3.1.2.2.7-1. Based on its review of the LRA and the applicant's response to RAI 3.1.2.2.7-1, the staff confirmed that the components are included with the reactorvessel system, class 1 piping, fittings and branch connections less than NPS 4". The staff also confirmed that the components are stainless steel with an external environment of air with borated water leakage and an internal environment of reactor coolant and the AMR results for these components are included in LRA Table 3.1.2-2, and are shown on pages 3.1-74 and 3.1-75 of the LRA. The staff finds the applicant's determination acceptable. SRP-LR Section 3.1.2.2.7.1 states that cracking due to SCC may occur in stainless steel reactor vessel flange leak detection lines and bottom-mounted instrument guide tubes exposed to reactor coolant. The GALL Report recommends that a plant-specific AMP be evaluated to ensure that this aging effect is adequately managed.In RAI 3.1.2.2.7-1, dated October 16, 2008, the staff requested that the applicant provide additional information to explain the basis for stating that the component, material, environment and aging effect/mechanism is not applicable. In its response to the RAI, dated November 12, 2008, the applicant stated that the reactor vessel closure head flange leak detection line and the bottom-mounted instrument guide tubes are included in the evaluation of reactor vessel class 1 piping, fittings, and branch connections of less than 4 inch nominal pipe size (<NPS 4"). The applicant stated that the components are stainless steel with an external environment of air with borated water leakage and an internal environment of reactor coolant. The applicant further stated that the AMR results for these components are included in LRA Table 3.1.2-2 on pages 3.1-74 and 3.1-75 of the LRA.3-166 components exposed to reactor coolant and neutron flux, with an aging effect of loss of fracture toughness due to neutron irradiation embrittlement and void swelling to be acceptable. Based on a review of the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.6 criteria. For those line items that apply to LRA Section 3.1.2.2.6, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 3.1.2.2.7 Cracking due to SCC 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 reactor vessel closure head flange leak detection line and bottom-mounted instrument guide tubes. The applicant stated that this component, material, environment, and aging effect/mechanism does not apply in the reactor vessel, internals, and reactor coolant system. The GALL Report recommends a plant specific AMP to manage cracking due to SCC in this component group. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that this line item is not applicable because the components are included with the reactor vessel system, class 1 piping, fittings and branch connections less than NPS 4". The applicant also stated that the components are stainless steel with an external environment of air with borated water leakage and an internal environment of reactor coolant and the AMR results for these components are included in LRA Table 3.1.2-2, and are shown on pages 3.1-74 and 3.1-75 of the LRA. The applicant also refers to its response to RAI 3.1.2.2.7-1. Based on its review of the LRA and the applicant's response to RAI 3.1.2.2.7-1, the staff confirmed that the components are included with the reactor vessel system, class 1 piping, fittings and branch connections less than NPS 4". The staff also confirmed that the components are stainless steel with an external environment of air with borated water leakage and an internal environment of reactor coolant and the AMR results for these components are included in LRA Table 3.1.2-2, and are shown on pages 3.1-74 and 3.1-75 of the LRA. The staff finds the applicant's determination acceptable. SRP-LR Section 3.1.2.2.7.1 states that cracking due to SCC may occur in stainless steel reactor vessel flange leak detection lines and bottom-mounted instrument guide tubes exposed to reactor coolant. The GALL Report recommends that a plant-specific AMP be evaluated to ensure that this aging effect is adequately managed. In RAI 3.1.2.2.7-1, dated October 16, 2008, the staff requested that the applicant provide additional information to explain the basis for stating that the component, material, environment and aging effect/mechanism is not applicable. In its response to the RAI, dated November 12, 2008, the applicant stated that the reactor vessel closure head flange leak detection line and the bottom-mounted instrument guide tubes are included in the evaluation of reactor vessel class 1 piping, fittings, and branch connections of less than 4 inch nominal pipe size <<NPS 4"). The applicant stated that the components are stainless steel with an external environment of air with borated water leakage and an internal environment of reactor coolant. The applicant further stated that the AMR results for these components are included in LRA Table 3.1.2-2 on pages 3.1-74 and 3.1-75 of the LRA. 3-166 The staff reviewed the AMR results identified by the applicant and noted that the AMR results lines identified by the applicant refer to LRA Table 3.1.1, item 3.1.1-70. The staff noted that the applicant proposed to manage the aging effect of cracking due to SCC in these components using the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD, and the Water Chemistry program. In RAI 3.1.2.2.7-2, dated January 5, 2009, the staff requested that the applicant provide additional information asking the applicant to explain how the examinations required by ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD, for small-bore piping will detect cracking in the reactor vessel closure head flange leak detection line and the bottom-mounted instrument guide tubes.In its response to the RAI, dated January 12, 2009, the applicant stated that the vessel closure head flange leak detection line is a 1" diameter blank flanged line and that, in accordance with ASME Code Section Xl, IWB-1220, piping of NPS 1" and smaller is exempt from volumetric and surface examination requirements. The applicant further stated that during normal operation or during hydrostatic test (VT-2 examinations) the line does not contain reactor coolant and is not pressurized. The applicant stated that this line would see pressure only if there were a leak at the inner reactor vessel closure flange 0-ring or if the annulus between the O-rings were pressurized, which is not a normal configuration, and that the normal internal environment for the flange leak detection line is air, which has no aging effects on stainless steel.With regard to the bottom-mounted instrument guide tubes, the applicant stated that a bare metal visual examination is performed on the bottom-mounted instrument guide tube nozzles in accordance with 10 CFR 50.55a, and that there has been no indication of bottom-mounted instrumentation nozzle leakage, no lower RPV boric acid leakage, and no RPV base metal wastage observed. The applicant stated that in addition, VT-2 examinations are performed every outage on the /" instrument guide tubes external to the vessel. The applicant stated that if indications of cracking or leakage are found in these components, an Issue Report is initiated to document the problem in accordance with the 10 CFR Part 50, Appendix B Corrective Action Program, and that corrective actions required by the applicant's program and ASME Code Section Xl are implemented. In evaluating the applicant's response with regard to the vessel head flange leak detection line, the staff noted that because the component is exempted from volumetric and surface examinations, and is not exposed to pressure during hydrostatic test, the applicant is, in fact, crediting only the Water Chemistry program for aging management of this component. The staff noted that this component normally is not a part of the reactor coolant pressure boundary, and that it is exposed to reactor coolant as part of the reactor coolant pressure boundary only if there is leakage past the inner reactor vessel closure flange O-ring. The staff also noted that the normal internal environment for this component is air, which does not have an aging effect on stainless steel components. On the basis that the normal internal environment is one where no aging effects are expected, the staff finds the applicant's crediting of the Water Chemistry program, alone, for aging management in the vessel head flange leak detection line to be acceptable. In evaluating the applicant's response with regard to the bottom mounted instrument guide tubes, the staff noted that the applicant is currently implementing all inspections of these components required by ASME Code Section XI, plus additional inspections required by 10 CFR 50.55a. The staff further noted that the VT-2 examinations of the bottom mountedinstrument guide tubes are performed at every refueling outage and provide on-going 3-167 The staff reviewed the AMR results identified by the applicant and noted that the AMR results lines identified by the applicant refer to LRA Table 3.1.1, item 3.1.1-70. The staff noted that the applicant proposed to manage the aging effect of cracking due to SCC in these components using the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD, and the Water Chemistry program. In RAI 3.1.2.2.7-2, dated January 5, 2009, the staff requested that the applicant provide additional information asking the applicant to explain how the examinations required by ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD, for small-bore piping will detect cracking in the reactor vessel closure head flange leak detection line and the bottom-mounted instrument guide tubes. In its response to the RAI, dated January 12, 2009, the applicant stated that the vessel closure head flange leak detection line is a 1" diameter blank flanged line and that, in accordance with ASME Code Section XI, IWB-1220, piping of NPS 1" and smaller is exempt from volumetric and surface examination requirements. The applicant further stated that during normal operation or during hydrostatic test (VT-2 examinations) the line does not contain reactor coolant and is not pressurized. The applicant stated that this line would see pressure only if there were a leak at the inner reactor vessel closure flange 0-ring or if the annulus between the a-rings were pressurized, which is not a normal configuration, and that the normal internal environment for the flange leak detection line is air, which has no aging effects on stainless steel. With regard to the bottom-mounted instrument guide tubes, the applicant stated that a bare metal visual examination is performed on the bottom-mounted instrument guide tube nozzles in accordance with 10 CFR 50.55a, and that there has been no indication of bottom-mounted instrumentation nozzle leakage, no lower RPV boric acid leakage, and no RPV base metal wastage observed. The applicant stated that in addition, VT-2 examinations are performed every outage on the instrument guide tubes external to the vessel. The applicant stated that if indications of cracking or leakage are found in these components, an Issue Report is initiated to document the problem in accordance with the 1 0 CFR Part 50, Appendix B Corrective Action Program, and that corrective actions required by the applicant's program and ASME Code Section XI are implemented. In evaluating the applicant's response with regard to the vessel head flange leak detection line, the staff noted that because the component is exempted from volumetric and surface examinations, and is not exposed to pressure during hydrostatic test, the applicant is, in fact, crediting only the Water Chemistry program for aging management of this component. The staff noted that this component normally is not a part of the reactor coolant pressure boundary, and that it is exposed to reactor coolant as part of the reactor coolant pressure boundary only if there is leakage past the inner reactor vessel closure flange O-ring. The staff also noted that the normal internal environment for this component is air, which does not have an aging effect on stainless steel components. On the basis that the normal internal environment is one where no aging effects are expected, the staff finds the applicant's crediting of the Water Chemistry program, alone, for aging management in the vessel head flange leak detection line to be acceptable. In evaluating the applicant's response with regard to the bottom mounted instrument guide tubes, the staff noted that the applicant is currently implementing all inspections of these components required by ASME Code Section XI, plus additional inspections required by 10 CFR 50.55a. The staff further noted that the VT-2 examinations of the bottom mounted instrument guide tubes are performed at every refueling outage and provide on-going 3-167 confirmation that cracking due to SCC has not occurred in these components. On the basis that ASME Code Section Xl inspections, as augmented by additional 10 CFR 50.55a inspections, provide capability of detecting cracking due to SCC, if it should occur, and the Water Chemistry program provides mitigation for the potential aging effect of cracking due to SCC in these components, the staff finds the applicant's crediting of the WaterChemistry program and the ASME Section Xl Inservice Inspection, Subsections IWB, IWC, and IWD program for aging management of the bottom mounted instrument guide tubes to be acceptable. The staffs concerns described in RAIs 3.1.2.2.7-1 and 3.1.2.2.7-2 are resolved.(2) LRA Section 3.1.2.2.7 addresses cracking due to SCC in class 1 cast austenitic stainless steel piping, piping components, and piping elements exposed to reactor coolant. The applicant stated that this component, material, environment, and aging effect/mechanism does not apply in the reactor vessel, internals, and reactor coolant system. The GALL Report recommends the Water Chemistry Program and for CASS components that do not meet the NUREG-0313 guidelines, a plant specific AMP to manage cracking due to stress corrosion cracking in this component group. In the applicant's response to RAI-AMR-GENERIC-2, the applicant stated that this line item is not applicable because with the exception of pump casings and valve bodies, there are no class 1 CASS piping, piping components, or piping elements in the reactor vessel, internals and reactor coolant system. The applicant also stated that cracking due to stress corrosion cracking in class 1 CASS pump casings and valve bodies is addressed by Item 3.1.1-68. The applicant also stated that item 3.1.1-24 specifies the Water Chemistry AMP and a plant specific AMP, while item 3.1.1-68 specifies the Water Chemistry AMP and ASME Xl IWB, IWC, and IWD AMP. The applicant also stated that the ASME Xl IWB, IWC, and IWD AMP is considered an acceptable plant specific program for managing cracking due to stress corrosion cracking in class 1 CASS pump casings and valve bodies. Based on its review of the LRA, the staff confirmed with the exception of pump casings and valve bodies, that there are no class 1 CASS piping, piping components, or piping elements in the reactor vessel, internals and reactor coolant system. The staff also confirmed that cracking due to stress corrosion cracking in class 1 CASS pump casings and valve bodies is addressed by item 3.1.1-68. The staff also confirmed that the ASME Xl IWB, IWC, and IWD AMP is an acceptable plant specific program for managing cracking due to stress corrosion cracking in class 1 CASS pump casings and valve bodies. The staff finds the applicant's determination acceptable. Based on a review of the programs identified above, the staff concludes that the applicant'sprograms meet SRP-LR Section 3.1.2.2.7 criteria. For those line items that apply to LRA Section 3.1.2.2.7, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 3.1.2.2.8 Cracking due to Cyclic Loading The staff reviewed LRA Section 3.1.2.2.8 against the criteria in SRP-LR Section 3.1.2.2.8. (1) LRA Section 3.1.2.2.8 addresses cracking due to cyclic loading stating that this aging effect is not applicable to TMI-1, which is a PWR.3-168 confirmation that cracking due to SCC has not occurred in these components. On the basis that ASME Code Section XI inspections, as augmented by additional 10 CFR 50.55a inspections, provide capability of detecting cracking due to SCC, if it should occur, and the Water Chemistry program provides mitigation for the potential aging effect of cracking due to SCC in these components, the staff finds the applicant's crediting of the Water Chemistry program and the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program for aging management of the bottom mounted instrument guide tubes to be acceptable. The staff's concerns described in RAls 3.1.2.2.7-1 and 3.1.2.2.7-2 are resolved. (2) LRA Section 3.1.2.2.7 addresses cracking due to SCC in class 1 cast austenitic stainless steel piping, piping components, and piping elements exposed to reactor coolant. The applicant stated that this component, material, environment, and aging effect/mechanism does not apply in the reactor vessel, internals, and reactor coolant system. The GALL Report recommends the Water Chemistry Program and for CASS components that do not meet the NUREG-0313 guidelines, a plant specific AMP to manage cracking due to stress corrosion cracking in this component group. In the applicant's response to GENERIC-2, the applicant stated that this line item is not applicable because with the exception of pump casings and valve bodies, there are no class 1 CASS piping, piping components, or piping elements in the reactor vessel, internals and reactor coolant system. The applicant also stated that cracking due to stress corrosion cracking in class 1 CASS pump casings and valve bodies is addressed by Item 3.1.1-68. The applicant also stated that item 3.1.1-24 specifies the Water Chemistry AMP and a plant specific AMP, while item 3.1.1-68 specifies the Water Chemistry AMP and ASME XI IWB, IWC, and IWD AMP. The applicant also stated that the ASME XIIWB, IWC, and IWD AMP is considered an acceptable plant specific program for managing cracking due to stress corrosion cracking in class 1 CASS pump casings and valve bodies. Based on its review of the LRA, the staff confirmed with the exception of pump casings and valve bodies, that there are no class 1 CASS piping, piping components, or piping elements in the reactor vessel, internals and reactor coolant system. The staff also confirmed that cracking due to stress corrosion cracking in class 1 CASS pump casings and valve bodies is addressed by item 3.1.1-68. The staff also confirmed that the ASME XI IWB, IWC, and IWD AMP is an acceptable plant specific program for managing cracking due to stress corrosion cracking in class 1 CASS pump casings and valve bodies. The staff finds the applicant's determination acceptable. Based on a review of the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.7 criteria. For those line items that apply to LRA Section 3.1.2.2.7, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21 (a)(3). 3.1.2.2.8 Cracking due to Cyclic Loading The staff reviewed LRA Section 3.1.2.2.8 against the criteria in SRP-LR Section 3.1.2.2.8. (1) LRA Section 3.1.2.2.8 addresses cracking due to cyclic loading stating that this aging effect is not applicable to TMI-1, which is a PWR. 3-168 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 TMI-1 because TMI-1 is a PWR 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 stating that this aging effect is not applicable to TMI-1, which is a PWR.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 TMI-1 because TMI-1 is a PWR 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 does not apply to TMI-1.3.1.2.2.9 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 the applicant's aging management basis for managing loss of preload due to stress relaxation in stainless steel and nickel alloy vessel internals screws and bolts exposed to reactor coolant and neutron flux. The applicant stated a commitment related to reactor vessel internals to: (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval. The applicant documented this commitment in LRA Appendix A, Commitment No. 36.The staff reviewed LRA Section 3.1.2.2.9 against the criteria in SRP-LR Section 3.1.2.2.9, which states that loss of preload due to stress relaxation may occur in stainless steel and nickel alloy PWR reactor vessel internals screws, bolts, tie rods, and hold-down springs exposed to reactor coolant. The GALL Report recommends no further aging management review if the applicantprovides a commitment in the UFSAR Supplement to (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval. The staff noted that the applicant's commitment stated in LRA Appendix A, Section A.5, is consistent with the commitment requirements described in SRP-LR Section 3.1.2.2.9. The staff also noted that all of the AMR results lines that refer to LRA Table 3.1.1, item 3.1.1-27, are aligned with the applicant's commitment for inspection of reactor vessel internals. On the basis that the applicant provides the appropriate commitment in the UFSAR Supplement and applicable AMR results are aligned with that commitment, the staff finds the applicant's AMR results for stainless steel and nickel alloy reactor vessel internal screws and bolts exposed to reactor coolant, with an aging effect of loss of preload to be acceptable. 3-169 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 TMI-1 because TMI-1 is a PWR 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 stating that this aging effect is not applicable to TMI-1, which is a PWR. 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 TMI-1 because TMI-1 is a PWR 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 does not apply to TMI-1. 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 the applicant's aging management basis for managing loss of preload due to stress relaxation in stainless steel and nickel alloy vessel internals screws and bolts exposed to reactor coolant and neutron flux. The applicant stated a commitment related to reactor vessel internals to: (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval. The applicant documented this commitment in LRA Appendix A, Commitment No. 36. The staff reviewed LRA Section 3.1.2.2.9 against the criteria in SRP-LR Section 3.1.2.2.9, which states that loss of preload due to stress relaxation may occur in stainless steel and nickel alloy , PWR reactor vessel internals screws, bolts, tie rods, and hold-down springs exposed to reactor , coolant. The GALL Report recommends no further aging management review if the applicant provides a commitment in the UFSAR Supplement to (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval. The staff noted that the applicant's commitment stated in LRA Appendix A, Section A.5, is consistent with the commitment requirements described in SRP-LR Section 3.1.2.2.9. The staff noted that all of the AMR results lines that refer to LRA Table 3.1.1, item 3.1.1-27, are aligned with the applicant's commitment for inspection of reactor vessel internals. On the basis that the applicant provides the appropriate commitment in the UFSAR Supplement and applicable AMR results are aligned with that commitment, the staff finds the applicant's AMR results for stainless steel and nickel alloy reactor vessel internal screws and bolts exposed to reactor coolant, with an aging effect of loss of preload to be acceptable. ' 3-169 Based on a review of the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.9 criteria. For those line items that apply to LRA Section 3.1.2.2.9, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 3.1.2.2.10 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 component, material, environment, and aging effect/mechanism does not apply to the reactor vessel, internals, and reactor coolant system.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. LRA Table 3.1 .1, line item 28, discusses the applicant's determination on a GALL AMR line item that is applicable only to recirculating steam generators. The staff confirmed that AMR line item 28, in Table 1 of the GALL Report, Volume 1 is only applicable to recirculating steam generators and confirmed by reviewing various sections of the LRA, that TMI-1 has once through steam generators. Based on this determination, the staff finds that AMR line item 28 in Table 1 of the GALL Report, Volume 1 is not applicable to TMI-I.Based on the above, the staff concludes that the recommended guidance in SRP-LR Section 3.1.2.2.10 does not apply to TMI-1.3.1.2.2.11 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 by stating that this aging effect is not applicable to TMI-1, which is a PWR.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 TMI-1 because TMI-1 is a PWR 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 TMI-I.3.1.2.2.12 Cracking due to SCC, and IASCC The staff reviewed LRA Section 3.1.2.2.12 against the criteria in SRP-LR Section 3.1.2.2.12. 3-170 Based on a review of the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.9 criteria. For those line items that apply to LRA Section 3.1.2.2.9, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended. function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3}. 3.1.2.2.10 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 feed water impingement plates and supports exposed to secondary feedwater, stating that this component, material, environment, and aging effect/mechanism does not apply to the reactor vessel, internals, and reactor coolant system. 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. LRA Table 3.1.1, line item 28, discusses the applicant's determination on a GALL AMR line item that is applicable only to recirculating steam generators. The staff confirmed that AMR line item 28, in Table 1 of the GALL Report, Volume 1 is only applicable to recirculating steam generators and confirmed by reviewing various sections of the LRA, that TMI-1 has once through steam generators. Based on this determination, the staff finds that AMR line item 28 in Table 1 of the GALL Report, Volume 1 is not applicable to TMI-1. Based on the above, the staff concludes that the recommended guidance in SRP-LR Section 3.1.2.2.10 does not apply to TMI-1. ;, 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 by stating that this aging effect is not applicable to TMI-1, which is a PWR. 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 TMI-1 because TMI-1 is a PWR 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 TMI-1. 3.1.2.2.12 Cracking due to SCC, and IASCC The staff reviewed LRA Section 3.1.2.2.12 against the criteria in SRP-LR Section 3.1.2,2.12. 3-170 LRA Section 3.1.2.2.12 addresses cracking due to SCC and IASCC in stainless steel reactor vessel internal components exposed to reactor coolant and neutron flux. The applicant stated acommitment related to reactor vessel internals to: (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval. The applicant stated that the aging effect of cracking due to SCC and IASCC will be managed by the Water Chemistry Program together with implementation of LRA Appendix A, Section A.5, Commitment No. 36.The staff reviewed LRA Section 3.1.2.2.12 against the criteria in SRP-LR Section 3.1.2.2.12, which states that cracking due to SCC and IASCC may occur in PWR stainless steel reactor internals exposed to reactor coolant and that the existing program relies on control of water chemistry to mitigate these effects. The GALL Report recommends no further aging management review if the applicant provides a commitment in the UFSAR Supplement to (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval.The staff reviewed the applicant's Water Chemistry program. The staffs evaluation of this program, which is documented in SER Section 3.0.3.2.2, determined that the Water Chemistry program, with an enhancement, is consistent with the program described in GALL AMP XI.M2,"Water Chemistry" and that the Water Chemistry program provides mitigation for the aging effect of cracking due to SCC and IASCC in stainless steel components exposed to reactor coolant.The staff reviewed the applicant's commitment related to the PWR Vessel Internals program in LRA Appendix A, Section A.5, Commitment No. 36. The staff also reviewed the AMR results lines in LRA Table 3.1.2-3 for stainless steel reactor vessel internal components exposed to reactor coolant and neutron flux, with an aging effect of cracking due to SCC and IASCC. The staff determined that the applicant provided a commitment for inspection of reactor vessel internals that is consistent with the commitment described in SRP-LR Section 3.1.2.2.12. The staff also determined that all of the applicable AMR results lines in LRA Table 3.1.2-3, as described above, are aligned with the applicant's commitment for inspection of reactor vessel internals and indicate that the Water Chemistry Program in combination with the commitment in the UFSAR Supplement is credited for managing the aging effect. Because the applicant provides the commitment in the UFSAR Supplement, as recommended in the SRP-LR and the GALL Report, and the applicant aligns appropriate AMR results with that commitment, indicating that both the Water Chemistry Program and the commitment are credited for aging management, the staff finds the applicant's AMR results to be consistent with the GALL Report. On this basis the staff finds the applicant's AMR results for stainless steel reactor vessel internal components exposed to reactor coolant and neutron flux, with an aging effect of cracking due to SCC and IASCC to be acceptable. Based on a review of the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.12 criteria. For those line items that apply to LRA Section 3.1.2.2.12, the staff 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 3-171 LRA Section 3.1.2.2.12 addresses cracking due to SCC and IASCC in stainless steel reactor vessel internal components exposed to reactor coolant and neutron flux. The applicant stated a commitment related to reactor vessel internals to: (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval. The applicant stated that the aging effect of cracking due to SCC and IASCC will be managed by the Water Chemistry Program together with implementation of LRA Appendix A, Section A.S, Commitment No. 36. . The staff reviewed LRA Section 3.1.2.2.12 against the criteria in SRP-LR Section 3.1.2.2.12, which states that cracking due to SCC and IASCC may occur in PWR stainless steel reactor internals exposed to reactor coolant and that the existing program relies on control of water chemistry to mitigate these effects. The GALL Report recommends no further aging management review if the applicant provides a commitment in the UFSAR Supplement to (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval. The staff reviewed the applicant's Water Chemistry program. The staffs evaluation of this program, which is documented in SER Section 3.0.3.2.2, determined that the Water Chemistry program, with an enhancement, is consistent with the program described in GALL AMP XI.M2, "Water Chemistry" and that the Water Chemistry program provides mitigation for the aging effect of cracking due to SCC and IASCC in stainless steel components exposed to reactor coolant. The staff reviewed the applicant's commitment related to the PWR Vessel Internals program in LRA Appendix A, Section A.S, Commitment No. 36. The staff also reviewed the AMR results lines in LRA Table 3.1.2-3 for stainless steel reactor vessel internal components exposed to reactor coolant and neutron flux, with an aging effect of cracking due to SCC and IASCC. The staff determined that the applicant provided a commitment for inspection of reactor vessel internals that is consistent with the commitment described in SRP-LR Section 3.1.2.2.12. The staff also determined that all of the applicable AMR results lines in LRA Table 3.1.2-3, as described above, are aligned with the applicant's commitment for inspection of reactor vessel internals and indicate that the Water Chemistry Program in combination with the commitment in the UFSAR Supplement is credited for managing the aging effect. Because the applicant provides the commitment in the UFSAR Supplement, as recommended in the SRP-LR and the GALL Report, and the applicant aligns appropriate AMR results with that commitment, indicating that both the Water Chemistry Program and the commitment are credited for aging management, the staff finds the applicant's AMR results to be consistent with the GALL Report. On this basis the staff finds the applicant's AMR results for stainless steel reactor vessel internal components. exposed to reactor coolant and neutron flux, with an aging effect of cracking due to SCC and IASCC to be acceptable. Based on a review of the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.12 criteria. For those line items that apply to LRA Section 3.1.2.2.12, the staff 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 3-171 intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21 (a)(3).3.1.2.2.13 Cracking due to PWSCC 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 states that the AMP B.2.1.1, "ASME Section Xl Inservice Inspection program, Subsections IWB, IWC, and IWD," the B.2.2.1, "Nickel Alloy Aging Management program," and the AMP B.2.1.2, "Water Chemistry program," will be implemented to manage the aging effects of cracking due to primary water stress corrosion cracking in nickel alloy and steel with nickel-alloy cladding piping components, piping elements, penetrations, nozzles, safe ends, and welds; pressurizer sleeves, diaphragm plate exposed to reactor coolant and treated water in the Core Flooding System, Reactor Coolant System, Reactor Vessel, and Steam Generator. The applicant stated that it complies with applicable NRC Orders and provides a commitment in the UFSAR Supplement to implement applicable (1) Bulletins and Generic Letters and (2) staff-accepted industry guidelines. The staff reviewed LRA Section 3.1.2.2.13 against the criteria in SRP-LR Section 3.1.2.2.13, which states that cracking due to PWSCC could occur in PWR components made of nickel alloy and steel with nickel alloy cladding, including reactor coolant pressure boundary components and penetrations inside the RCS such as pressurizer heater sheathes and sleeves, nozzles, and other internal components. With the exception of reactor vessel upper head nozzles and penetrations, the GALL Report recommends ASME Section Xl ISI (for Class 1 components) and control of water chemistry. For nickel alloy components, no further aging management review is necessary if the applicant complies with applicable NRC Orders and provides a commitment in the UFSAR Supplement to implement applicable (1) Bulletins and Generic Letters and (2) staff-accepted industry guidelines. The staff finds that the applicant has met the criteria of SRP-LR Section 3.1.2.2.13, because the applicant has committed in LRA Appendix A (Commitment

35) to implement NRC Bulletins and Generic Letters and industry guidelines to manage PWSCC of RCS components fabricated with nickel alloys including base metals and welds as part of LRA AMP B.2.2. 1.A revision to 10 CFR 50.55a, "Codes and Standards" was issued September 2008 which requires all licensee of pressurized water reactors to augment their inservice inspection programs to implement ASME Code Case N-722 which provides for additional detection capability for partial or full penetration welds in Class1 components fabricated with Alloy600/82/182 material pressure boundary leakage in pressurized water reactor plants. The applicant's LRA does not address the new provisions of 10 CFR 50.55a because it was submitted January 2008. The staff discussed this issue with the applicant, who indicated that the changes have been incorporated into aninterim revision of the ISI Program and that its scheduling database has been updated to reflect the inspection requirements of ASME Code Case N-722. The applicant also indicated that there is no impact to any AMRs as a result of the revision to the regulation.

The staff further discussed this issue with the applicant on June 29, 2009 who indicated that the ISI program and the corresponding basis document have been updated based on the revised requirements. Based on its review, the staff finds the applicant's implementation of the provisions of 10 CR 50.55a and ASME Code Case N-722, acceptable. 3-172 intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21 (a)(3). 3.1.2.2.13 Cracking due to PWSCC 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 states that the AMP B.2.1.1, "ASME Section XI Inservice Inspection program, Subsections IWB, IWC, and IWD," the B.2.2.1, "Nickel Alloy Aging Management program," and the AMP B.2.1.2, "Water Chemistry program," will be implemented to manage the aging effects of cracking due to primary water stress corrosion cracking in nickel alloy and steel with nickel-alldy cladding piping components, piping elements, penetrations, nozzles, safe ends, and welds; pressurizer sleeves, diaphragm plate exposed to reactor coolant and treated water in the Core Flooding System, Reactor Coolant System, Reactor Vessel, and Steam Generator. The applicant stated that it complies with applicable NRC Orders and provides a commitment in the UFSAR Supplement to implement applicable (1) Bulletins and Generic Letters and (2) accepted industry guidelines. The staff reviewed LRA Section 3.1.2.2.13 against the criteria in SRP-LR Section 3.1.2.2.13, which states that cracking due to PWSCC could occur in PWR components made of nickel alloy and steel with nickel alloy cladding, including reactor coolant pressure boundary components and penetrations inside the RCS such as pressurizer heater sheathes and sleeves, nozzles, and other internal components. With the exception of reactor vessel upper head nozzles and penetrations, the GALL Report recommends ASME Section XI lSI (for Class 1 components) and control of water chemistry. For nickel alloy components, no further aging management review is necessary if the applicant.complies with applicable NRC Orders and provides a commitment in the UFSAR Supplement to implement applicable (1) Bulletins and Generic Letters and (2) staff-accepted industry guidelines. The staff finds that the applicant has met the criteria of SRP-LR Section 3.1.2.2.13, because the applicant has committed in LRA Appendix A (Commitment

35) to implement NRC Bulletins and Generic Letters and industry guidelines to manage PWSCC of RCS components fabricated with nickel alloys including base metals and welds as part of LRA AMP B.2.2.1. A revision to 10 CFR 50.55a, "Codes and Standards" was issued September 2008 which requires all licensee of pressurized water reactors to augment their inservice inspection programs to implement ASME Code Case N,.722 which provides for additional detection capability for partial or full penetration welds in Class 1 components fabricated with Alloy600/82/182 material pressure boundary leakage in pressurized water reactor plants. The applicant's LRA does not address the new provisions of 10 CFR 50.55a because it was submitted January 2008. The staff discussed this issue with the applicant, who indicated that the changes have been incorporated into an interim revision of the lSI Program and that its scheduling database has been updated to reflect the inspection requirements of ASME Code Case N-722. The applicant also indicated that there is no impact to any AMRs as a result of the revision to the regulation.

The staff further discussed this issue with the applicant on June 29, 2009 who indicated that the lSI program and the corresponding basis document have been updated based on the revised requirements. Based on its review, the staff finds the applicant's implementation of the provisions of 10 CR 50.55a and ASME Code Case N-722, acceptable. 3-172 Based on a review of the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.13 criteria. For those line items that apply to LRA Section 3.1.2.2.13 the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 3.1.2.2.14 Wall Thinning due to FAC 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. The applicant stated that this line item is not applicable and further stated that wall thinning due to flow-accelerated corrosion in the steel feedwater inlet ring is discussed in Item Number 3.4.1-29.The staff reviewed LRA Section 3.1.2.2.14 against the criteria in SRP Section 3.1.2.2.14, which states that wall thinning due to flow-accelerated corrosion, may occur in steel FW inlet rings and supports. The GALL Report references IN 91-19, "Steam Generator Feedwater Distribution Piping Damage," for evidence of flow-accelerated corrosion in steam generators and recommends that a plant-specific AMP be evaluated because existing programs may not be capable of mitigating or detecting wall thinning due to flow-accelerated corrosion.The corresponding GALL Report line item is IV.D1-26. For this line item, the GALL Report recommends a plant-specific program to be evaluated. The staff reviewed LRA Table 3.4.1, line item 3.4.1-29 and noted that there is no discussion of steel steam generator feedwater inlet ring.This line item further states that it is not consistent with the GALL Report and provides an explanation for the emergency feedwater system, only. In RAI 3.1.2.2.14-1, dated October 16, 2008, the staff requested that the applicant provide additional information to justify why line item 3.1.1-32 is not applicable and explain how the discussion in LRA Table 3.4.1, line item 3.4.1-29 is applicable to LRA Table 3.1.1, line item 3.1.1-32.In its response to the RAI dated November 12, 2008, the applicant stated that Section 3.1.2.2.14 is for a feedwater inlet ring internal to the steam generator associated with Westinghouse and Combustion Engineering Recirculating Steam Generators and is not applicable to TMI-1, which is a Once Through Steam Generator. In order to eliminate confusion, the applicant revised LRA Table 3.1.1, line item 3.1.1-32 discussion to state the following: Not Applicable. See Subsection 3.1.2.2.14. In addition, the applicant revised Section 3.1.2.2.14 of the LRA to state the following: Not Applicable. The discussion for Section 3.1.2.2.14 is for a feedwater inlet ring internal to the steam generator which is associated with Westinghouse and Combustion Engineering Steam Generators and is not applicable to TMI-1.The staff reviewed the applicant's response and the GALL Report. The staff noted that GALL Report Volume 2, item IV.D1-26 is applicable to Recirculating Type Steam Generators and there is no equivalent line item in the GALL Report in Section IV.D2 for Once Through Steam Generators. Based on this review, the staff finds the applicant response acceptable and concurs that Table 3.1.1, item 3.1.1-32 is not applicable for TMI-1. The staffs concern described in RAI 3.1.2.2.14-1 is resolved.3-173 Based on a review of the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.13 criteria. For those line items that apply to LRA Section 3.1.2.2.13 the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 3.1.2.2.14 Wall Thinning due to FAC 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. The applicant stated that this line item is not applicable and further stated that wall thinning due to accelerated corrosion in the steel feedwater inlet ring is discussed in Item Number 3.4.1-29. The staff reviewed LRA Section 3.1.2.2.14 against the criteria in SRP Section 3.1.2.2.14, which states that wall thinning due to flow-accelerated corrosion, may occur in steel FW inlet rings and supports. The GALL Report references IN 91-19, "Steam Generator Feedwater Distribution Piping Damage," for evidence of flow-accelerated corrosion in steam generators and recommends that a plant-specific AMP be evaluated because existing programs may not be capable of mitigating or detecting wall thinning due to flow-accelerated corrosion. The corresponding GALL Report line item is IV.D1-26. For this line item, the GALL Report recommends a plant-specific program to be evaluated. The staff reviewed LRA Table 3.4.1, line item 3.4.1-29 and noted that there is no discussion of steel steam generator feedwater inlet ring. This line item further states that it is not consistent with the GALL Report and provides an explanation for the emergency feedwater system, only. In RAI 3.1.2.2.14-1, dated October 16, 2008, the staff requested that the applicant provide additional information to justify why line item 3.1.1-32 is not applicable and explain how the discussion in LRA Table 3.4.1, line item 3.4.1-29 is applicable to LRA Table 3.1.1, line item 3.1.1-32. In its response to the RAI dated November 12, 2008, the applicant stated that Section 3.1.2.2.14 is for a feedwater inlet ring internal to the steam generator associated with Westinghouse and Combustion Engineering ReCirculating Steam Generators and is not applicable to TMI-1, which is a Once Through Steam Generator. In order to eliminate confusion, the applicant revised LRA Table 3.1.1, line item 3.1.1-32 discussion to state the following: Not Applicable. See Subsection 3.1.2.2.14. In addition, the applicant revised Section 3.1.2.2.14 of the LRA to state the following: Not Applicable. The discussion for Section 3.1.2.2.14 is for a feedwater inlet ring internal to the steam generator which is associated with Westinghouse and Combustion Engineering Steam Generators and is not applicable to TMI-1. The staff reviewed the applicant's response and the GALL Report. The staff noted that GALL Report Volume 2, item IV.D1-26 is applicable to Recirculating Type Steam Generators and there is no equivalent line item in the GALL Report in Section IV.D2 for Once Through Steam Generators. Based on this review, the staff finds the applicant response acceptable and concurs that Table 3.1.1, item 3.1.1-32 is not applicable for TMI-1. The staffs concern described in RAI 3.1.2.2.14-1 is resolved. 3-173 Based on a review of the programs identified above, the staff concludes that the applicant'sprograms 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 function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 3.1.2.2.15 Changes in Dimensions due to Void Swelling The staff reviewed LRA Section 3.1.2.2.15 against the criteria in SRP-LR Section 3.1.2.2.15. LRA Section 3.1.2.2.15 addresses changes in dimensions due to void swelling in stainless steel and nickel alloy reactor vessel internal components exposed to reactor coolant and neutron flux.The applicant stated a commitment related to reactor vessel internals to: (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval. The applicant documented this commitment in LRA Appendix A, Final Safety Analysis Report Supplement, Section A.5, License Renewal Commitment List, Commitment No. 36.The staff reviewed LRA Section 3.1.2.2.15 against the criteria in SRP-LR Section 3.1.2.2.15, which states that changes in dimensions due to void swelling may occur in stainless steel and nickel alloy PWR reactor internal components exposed to reactor coolant. The GALL Report recommends no further aging management review if the applicant provides a commitment in the UFSAR Supplement to (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval.The staff noted that the applicant's commitment stated in LRA Appendix A, Section A.5, is consistent with the commitment requirements described in SRP-LR Section 3.1.2.2.15. The staff also noted that all of the AMR results lines that refer to LRA Table 3.1.1, item 3.1.1-33 are aligned with the applicant's commitment for inspection of reactor vessel internals. On the basis that the applicant provides the appropriate commitment in the UFSAR Supplement and applicable AMR results are aligned with that commitment, the staff finds the applicant's AMR results for stainless steel and nickel alloy reactor vessel internals components exposed to reactor coolant and neutron flux, with an aging effect of changes in dimensions due to void swelling, to be acceptable. Based on a review of the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.15 criteria. For those line items that apply to LRA Section3.1.2.2.15, 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 function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 3-174 Based on a review of the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.14 criteria. For those line items that apply to LRA Section 3.1.2.2.14 the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by10 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 in stainless steel and nickel alloy reactor vessel internal components exposed to reactor coolant and neutron flux. The applicant stated a commitment related to reactor vessel internals to: (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval. The applicant documented this commitment in LRA Appendix A, Final Safety Analysis Report Supplement, Section A.5, License Renewal Commitment List, Commitment No. 36. The staff reviewed LRA Section 3.1.2.2.15 against the criteria in SRP-LR Section 3.1.2.2.15, which states that changes in dimensions due to void swelling may occur in stainless steel and nickel alloy PWR reactor internal components exposed to reactor coolant. The GALL Report recommends no further aging management review if the applicant provides a commitment in the UFSAR Supplement to (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval. The staff noted that the applicant's commitment stated in LRA Appendix A, Section A. 5, is consistent with the commitment requirements described in SRP-LR Section 3.1.2.2.15. The staff also noted that all of the AMR results lines that refer to LRA Table 3.1.1, item 3.1.1-33 are aligned with the applicant's commitment for inspection of reactor vessel internals. On the basis that the applicant provides the appropriate commitment in the UFSAR Supplement and applicable AMR results are aligned with that commitment, the staff finds the applicant's AMR results for stainless steel and nickel alloy reactor vessel internals components exposed to reactor coolant and neutron flux, with an aging effect of changes in dimensions due to void swelling, to be acceptable. Based on a review of the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.15 criteria. For those line items that apply to LRA Section 3.1.2.2.15, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21 (a)(3). 3-174 3.1.2.2.16 Cracking due to SCC and PWSCC 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 states that: " The ASME Section Xl Inservice Inspection Program, Subsections IWB, IWC, and IWD, B.2.1.1, and the Water Chemistry program, B.2.1.2, will be implemented to manage cracking due to stress corrosion cracking in stainless steel reactor control rod drive head penetration pressure housings." The ASME Section XI Inservice Inspection Program, Subsections IWB, IWC, and IWD, B.2.1.1, the Nickel Alloy Aging Management program, B.2.2.1, and the WaterChemistry program, B.2.1.2, will be implemented to manage cracking due to primary water stress corrosion cracking in nickel alloy and steel with nickel-alloy cladding reactor control rod drive head penetration pressure housings.* The ASME Section Xl Inservice Inspection Program, Subsections IWB, IWC, and IWD, B.2.1.1, and the Water Chemistry program, B.2.1.2, will be implemented to manage the aging effects of cracking due to stress corrosion cracking in steel with stainless steel cladding primary side components, steam generator upper and lower heads, and stainless steel tube support plates.* The ASME Section XI Inservice Inspection Program, Subsections IWB, IWC, and IWD, B.2.1.1, and the Nickel Alloy Aging Management program, B.2.2.1, and the Water Chemistry program, B.2.1.2, will be implemented to manage the aging effects of cracking due to primary water stress corrosion cracking in steel with nickel-alloy cladding steam generator tubesheets. TMI-1 complies with applicable NRC Orders and provides a commitment in the UFSAR Supplement to implement applicable (1)Bulletins and Generic Letters and (2) staff-accepted industry guidelines.The staff reviewed LRA Section 3.1.2.2.16 against the criteria in SRP-LR Section 3.1.2.2.16 which states that cracking due to SCC could 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. The SRP-LR states cracking due to PWSCC could 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 Section XI ISI and control of water chemistry to manage this aging effect and recommends no further aging management review for PWSCC of nickel alloy if the applicant complies with applicable NRC Orders and provides a commitment in the UFSAR Supplement to implement applicable (1) Bulletins and Generic Letters and (2)staff-accepted industry guidelines.The staff noted that in the LRA Appendix A (commitments 1 and 2) the applicant has committed to implement the ASME Section XI Inservice Inspection program and the Water Chemistry program as recommended by the GALL report to manage SCC of applicable stainless steel components and PWSCC of applicable nickel-alloy components. Also, the staff reviewed the applicant's Nickel Aging Management program, B.2.2.1 in SER Section 3.0.3.3.1 and noted that the applicant has committed to implement applicable NRC Orders and provides a commitment (commitment

35) in LRA Appendix A to implement applicable (1) Bulletins and Generic Letters and (2) staff-accepted industry guidelines.

Therefore, the 3-175 3.1.2.2.16 Cracking due to SCC and PWSCC The staff reviewep 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 states that:

  • The ASME Section Xllnservice Inspection Program, Subsections IWB, IWC, and IWO, B.2.1.1, and the Water Chemistry program, B.2.1.2, will be implemented to manage cracking due to stress corrosion cracking in stainless steel reactor control rod drive head penetration pressure housings.
  • The ASME Section XI Inservice Inspection Program, Subsections IWB, IWC, and IWO, B.2.1.1, the Nickel Alloy Aging Management program, B.2.2.1, and the Water Chemistry program, B.2.1.2, will be implemented to manage cracking due to primary water stress corrosion cracking in nickel alloy and steel with nickel-alloy cladding reactor control rod drive head penetration pressure housings.
  • The ASME Section XI Inservice Inspection Program, Subsections IWB, IWC, and IWO, B.2.1.1, and the Water Chemistry program, B.2.1.2, will be implemented to manage the aging effects of cracking due to stress corrosion cracking in steel with stainless steel cladding primary side components, steam generator upper and lower heads, and stainless steel tube support plates.
  • The ASME Section Xllnservice Inspection Program, Subsections IWB, IWC, and IWO, B.2.1.1, and the Nickel Alloy Aging Management program, B.2.2.1, and the Water Chemistry program, B.2.1.2, will be implemented to manage the aging effects of cracking due to primary water stress corrosion cracking in steel with nickel-alloy cladding steam generator tubesheets.

TMI-1 complies with applicable NRC Orders and provides a commitment in the UFSAR Supplement to implement applicable (1) Bulletins and Generic Letters and (2) staff-accepted industry guidelines. The staff reviewed LRA Section 3.1.2.2.16 against the criteria in SRP-LR Section 3.1.2.2.16 which states that cracking due to SCC could 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. The SRP-LR states cracking due to PWSCC could 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 Section XI lSI and control of water chemistry to manage this aging effect and recommends no further aging management review for PWSCC of nickel alloy if the applicant complies with applicable NRC Orders and provides a commitment in the UFSAR Supplement to implement applicable (1) Bulletins and Generic Letters and (2) staff-accepted industry guidelines. The staff noted that in the LRA Appendix A (commitments 1 and 2) the applicant has committed to implement the ASME Section XI Inservice Inspection program and the Water Chemistry program as recommended by the GALL report to manage SCC of applicable stainless steel components and PWSCC of applicable nickel-alloy components. Also, the staff reviewed the applicant's Nickel Aging Management program, B.2.2.1 in SER Section 3.0.3.3.1 and noted that the applicant has committed to implement applicable NRC Orders and provides a commitment (commitment

35) in LRA Appendix A to implement applicable (1) Bulletins and Generic Letters and (2) staff-accepted industry guidelines.

Therefore, the 3-175 staff finds that, based on a review of the programs identified above, no further aging management review for PWSCC of nickel alloy is required by the applicant. A revision to 10 CFR 50.55a, "Codes and Standards" was issued September 2008 which requires all licensee of pressurized water reactors to augment their inservice inspection programs to implement ASME Code Case N-722 which provides for additional detection capability for partial or full penetration welds in Class1 components fabricated with Alloy600/82/182 material pressure boundary leakage in pressurized water reactor plants.The applicant's LRA does not address the new provisions of 10 CFR 50.55a because it was submitted January 2008. The staff discussed this issue with the applicant who indicated that the changes have been incorporated into an interim revision of the ISI Program and that its scheduling database has been updated to reflect the inspection requirements of ASME Code Case N-722. The applicant also indicated that there is no impact to any AMRs as a result of the revision to the regulation. Based on its review, the staff finds the applicant's implementation of the provisions of 10 CFR 50.55a and ASME Code Case N-722, acceptable. (2) LRA Section 3.1.2.2.16 addresses cracking due to stress corrosion cracking and primary water stress corrosion cracking in the nickel alloy pressurizer spray head. The applicant stated that the pressurizer spray head does not perform an intended function and is not in scope for license renewal for the reactor vessel, internals and reactor coolant system.The staff confirmed that the pressurizer spray head is not part of the reactor coolant pressure boundary and that it does not perform a license renewal intended function.Because the pressurizer spray head does not perform a license renewal intended function, the staff finds that an aging management review of the pressurizer spray head is not required. On this basis, the staff finds it acceptable for the applicant to designate LRA Table 3.1.1, line item 3.1.1-36, as not applicable. Based on a review of the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.16 criteria. For those line items that apply to LRA Section 3.1.2.2.16 the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 3.1.2.2.17 Cracking due to SCC, PWSCC, and IASCC 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 the applicant's aging management basis for managing cracking due to SCC, PWSCC, and IASCC in stainless steel and nickel alloy reactor vessel components exposed to reactor coolant and neutron flux. The applicant stated a commitment related to reactor vessel internals to: (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval. The applicant stated that the aging effect of cracking due to SCC, PWSCC, and IASCC will be managed by the Water Chemistry program together with implementation of the commitment, which is documented in LRA Appendix A, Final Safety Analysis Report Supplement, Section A.5, License Renewal Commitment List, Commitment No. 36.3-176 staff finds that, based on a review of the programs identified above, no further aging management review for PWSCC of nickel alloy is required by the applicant. A revision to 10 CFR 50.55a, "Codes and Standards" was issued September 2008 which requires all licensee of pressurized water reactors to augment their inservice inspection programs to implement ASME Code Case N-722 which provides for additional detection capabiiity for partial or full penetration welds in Class 1 components fabricated with Alloy600/82/182 material pressure boundary leakage in pressurized water reactor plants. The applicant's LRA does not address the new provisions of 10 CFR 50.55a because it was submitted January 2008. The staff discussed this issue with the applicant who indicated that the changes have been incorporated into an interim revision of the lSI Program and that its scheduling database has been updated to reflect the inspection requirements of ASME Code Case N-722. The applicant also indicated that there is no impact to any AMRs as a result of the revision to the regulation. Based on its review, the staff finds the applicant's implementation of the provisions of 10 CFR 50.55a and ASME Code Case N-722, acceptable. (2) LRA Section 3.1.2.2.16 addresses cracking due to stress corrosion cracking and primary water stress corrosion cracking in the nickel alloy pressurizer spray head. The applicant stated that the pressurizer spray head does not perform an intended function and is not in scope for license renewal for the reactor vessel, internals and reactor coolant system. The staff confirmed that the pressurizer spray head is not part of the reactor coolant pressure boundary and that it does not perform a license renewal intended function. Because the pressurizer spray head does not perform a license renewal intended function, the staff finds that an aging management review of the pressurizer spray head is not required. On this basis, the staff finds it acceptable for the applicant to designate LRA Table 3.1.1, line item 3.1.1-36, as not applicable. Based on a review of the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.16 criteria. For those line items that apply to LRA Section 3.1.2.2.16 the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 3.1.2.2.17 Cracking due to SCC, PWSCC, and IASCC 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 the applicant's aging management basis for managing cracking due to SCC, PWSCC, and IASCC in stainless steel and nickel alloy reactor vessel components exposed to reactor coolant and neutron flux. The applicant stated a commitment related to reactor vessel internals to: (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval. The applicant stated that the aging effect of cracking due to SCC, PWSCC, and IASCC will be managed by the Water Chemistry program together with implementation of the commitment, which is documented in LRA Appendix A, Final Safety Analysis Report Supplement, Section A.5, License Renewal Commitment List, Commitment No. 36. 3-176 The staff reviewed LRA Section 3.1.2.2.17 against the criteria in SRP-LR Section 3.1.2.2.17, which states that cracking due to SCC, PWSCC, and IASCC may occur in stainless steel and nickel alloy reactor vessel internals components. The SRP-LR states that the existing program relies on control of water chemistry to mitigate these effects; however, the existing programshould be augmented to manage these aging effects for reactor vessel internals components. The GALL Report recommends no further aging management review if the applicant provides a commitment in the UFSAR Supplement to (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval.The staff reviewed the applicant's Water Chemistry program. The staffs evaluation of this program, which is documented in SER Section 3.0.3.2.2, determined that the Water Chemistry program, with an enhancement, is consistent with the program described in GALL AMP XI.M2,"Water Chemistry" and that the Water Chemistry program provides mitigation for the aging effect of cracking due to SCC, PWSCC and IASCC in stainless steel components exposed to reactor coolant.The staff reviewed LRA Appendix A, Commitment No. 36, that relates to the PWR Vessel Internals program. The staff also reviewed the AMR results lines in LRA Table 3.1.2-3 for stainless steel reactor vessel internal components exposed to reactor coolant and neutron flux, with an aging effect of cracking due to SCC, PWSCC, and IASCC. The staff determined that the applicant provided a commitment for inspection of reactor vessel internals that is consistent with the commitment described in SRP-LR Section 3.1.2.2.17. The staff also determined that all of the applicable AMR results lines in LRA Table 3.1.2-3, as described above, are aligned with the applicant's commitment for inspection of reactor vessel internals and indicate that the Water Chemistry program in combination with the UFSAR commitment is credited for managing the aging effect. Because the applicant provides the commitment in the UFSAR Supplement, as recommended in the SRP-LR and the GALL Report, and the applicant aligns appropriate AMR results with that commitment, indicating that both the Water Chemistry program and the commitment are credited for aging management, the staff finds the applicant's AMR results to be consistent with the GALL Report. On this basis the staff finds the applicant's AMR results for stainless steel reactor vessel internals components exposed to reactor coolant and neutron flux, with an aging effect of cracking due to SCC, PWSCC and IASCC to be acceptable. Based on a review of the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.17 criteria. For those line items that apply to LRA Section 3.1.2.2.17, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21 (a)(3).3.1.2.2.18 Quality Assurance for Aging Management of Nonsafety-Related Components SER Section 3.0.4 provides the staff's evaluation of the applicant's QA program.3-177 The staff reviewed LRA Section 3.1.2.2.17 against the criteria in SRP-LR Section 3.1.2.2.17, which states that cracking due to SCC, PWSCC, and IASCC may occur in stainless steel and nickel alloy reactor vessel internals components. The SRP-LR states that the existing program relies on control of water chemistry to mitigate these effects; however, the eXisting program should be augmented to manage these aging effects for reactor vessel internals components. The GALL Report recommends no further aging management review if the applicant provides a commitment in the UFSAR Supplement to (1) participate in .the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval. The staff reviewed the applicant's Water Chemistry program. The staff's evaluation of this program, which is documented in SER Section 3.0.3.2.2, determined that the Water Chemistry program, with an enhancement, is consistent with the program described in GALL AMP XI.M2, "Water Chemistry" and that the Water Chemistry program provides mitigation for the aging effect of cracking due to SCC, PWSCC and IASCC in stainless steel components exposed to reactor coolant. The staff reviewed LRA Appendix A, Commitment No. 36, that relates to the PWR Vessel Internals program. The staff also reviewed the AMR results lines in LRA Table 3.1.2-3 for stainless steel reactor vessel internal components exposed to reactor coolant and neutron flux, with an aging effect of cracking due to SCC, PWSCC, and IASCC. The staff determined that the applicant provided a commitment for inspection of reactor vessel internals that is consistent with the commitment described in SRP-LR Section 3.1.2.2.17. The staff also determined that all of the applicable AMR results lines in LRA Table 3.1.2-3, as described above, are aligned with the applicant's commitment for inspection of reactor vessel internals and indicate that the Water Chemistry program in combination with the UFSAR commitment is credited for managing the aging effect. Because the applicant provides the commitment in the UFSAR Supplement, as recommended in the SRP-LR and the GALL Report, and the applicant aligns appropriate AMR results with that commitment, indicating that both the Water Chemistry program and the commitment are credited for aging management, the staff finds the applicant's AMR results to be consistent with the GALL Report. On this basis the staff finds the applicant's AMR results for stainless steel reactor vessel internals components exposed to reactor coolant and neutron flux, with an aging effect of cracking due to SCC, PWSCC and IASCC to be acceptable. Based on a review of the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.17 criteria. For those line items that apply to LRA Section 3.1.2.2.17, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21 (a)(3). 3.1.2.2.18 Quality Assurance for Aging Management of Nonsafety-Related Components SER Section 3.0.4 provides the staff's evaluation of the applicant's QA program. 3-177 3.1.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report In LRA Tables 3.1.2-1 through 3.1.2-4, the staff reviewed additional details of AMR results for material, environment, AERM, and AMP combinations not consistent with or not addressed in the GALL Report.In LRA Tables 3.1.2-1 through 3.1.2-4, the applicant indicated, via Notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report. The applicant provided further information concerning how the aging effects will be managed. Specifically, Note F indicates that the material for the AMR line item component is not evaluated in the GALL Report. Note G indicates that the environment for the AMR line item component and material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR line item component, material, and environment combination is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the line item component, material, and environment combination is not applicable. Note J indicates that neither the component nor the material and environment combination for the line item is evaluated in the GALL Report.For component type, material, and environment combinations not evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine whether the applicant had demonstrated that the aging effects will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation. The staffs evaluation is discussed in the following sections.3.1.2.3.1 Reactor Coolant System -Reactor Coolant System -Summary of Aging Management Evaluation -LRA Table 3.1.2-1 The staff reviewed LRA Table 3.1.2-1 which summarizes the results of AMR evaluations for the reactor coolant system component groups.For nickel alloy piping and fittings, pressurizer instrumentation penetrations, heater sheaths and sleeves, heater bundle diaphragm plate, and manways and flanges (Heater Bundle Diaphragm &Instrumentation Nozzle Safe Ends and Heater Sleeve), Pressurizer surge and steam space nozzles, and welds, reactor coolant pressure boundary components, and thermowells exposed to an air with borated water leakage (external) environment, the applicant assigned no aging effectand therefore no aging management program was assigned for these component/material/environment combinations. The staff noted that austenitic materials such as nickel alloys are not subject to loss of material or cracking when subjected to this environment and these materials are used as corrosion resistant replacement materials where other materials have degraded. According to EPRI NP-5769,"Degradation and Failure of Bolting in Nuclear Power Plants, Volumes 1 and 2, April 1988, corrosion resistant materials such as austenitic and martensitic stainless steels and high strength nickel base alloys offer good protection against boric acid corrosion. Therefore no aging management program is necessary for nickel alloys in the air with borated water leakage (external) environment. The applicant stated that for gray cast iron pump casings and carbon steel valve bodies exposed to a lubricating oil environment in the reactor coolant system (Table 3.1.2-1), the aging effect for the AMR line item component, material, and environment combination is not evaluated in the GALL Report. The staff reviewed the GALL Report and concluded that the AMR line item, gray 3-178 3.1.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report In LRA Tables 3.1.2-1 through 3.1.2-4, the staff reviewed additional details of AMR results for material, environment, AERM, and AMP combinations not consistent with or not addressed in the GALL Report. In LRA Tables 3.1.2-1 through 3.1.2-4, the applicant indicated, via Notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report. The applicant provided further information concerning how the aging effects will be managed. Specifically, Note F indicates that the material for the AMR line item component is not evaluated in the GALL Report. Note G indicates that the environment for the AMR line item component and material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR line item component, material, and environment combination is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the line item component, material, and environment combination is not applicable. Note J indicates that neither the component nor the material and environment combination for the line item is evaluated in the GALL Report. For component type, material, and environment combinations not evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine whether the applicant had demonstrated that the aging effects will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation. The staff's evaluation is discussed in the following sections. 3.1.2.3.1 Reactor Coolant System -Reactor Coolant System -Summary of Aging Management Evaluation -LRA Table 3.1.2-1 The staff reviewed LRA Table 3.1.2-1 which summarizes the results of AMR evaluations for the reactor coolant system component groups. For nickel alloy piping and fittings, pressurizer instrumentation penetrations, heater sheaths and sleeves, heater bundle diaphragm plate, and manways and flanges (Heater Bundle Diaphragm & Instrumentation Nozzle Safe Ends and Heater Sleeve), Pressurizer surge and steam space nozzles, and welds, reactor coolant pressure boundary components, and thermowells exposed to an air with borated water leakage (external) environment, the applicant assigned no aging effect and therefore no aging management program was assigned for these component/material/environment combinations. The staff noted that austenitic materials such as nickel alloys are not subject to loss of material or cracking when subjected to this environment and these materials are used as corrosion resistant replacement materials where other materials have degraded. According to EPRI NP-5769, "Degradation and Failure of Bolting in Nuclear Power Plants, Volumes 1 and 2, April 1988, corrosion resistant materials such as austenitic and martensitic stainless steels and high strength nickel base alloys offer good protection against boric acid corrosion. Therefore no aging management program is necessary for nickel alloys in the air with borated water leakage (external) environment. The applicant stated that for gray cast iron pump casings and carbon steel valve bodies exposed to a lubricating oil environment in the reactor coolant system (Table 3.1.2-1), the aging effect for the AMR line item component, material, and environment combination is not evaluated in the GALL Report. The staff reviewed the GALL Report and concluded that the AMR line item, gray 3-178 cast iron pump casings and carbon steel valve bodies is not evaluated for a lubricating oil environment for loss of material due to pitting, crevice, microbiologically influence. The applicant credits the Lubricating Oil Analysis Program and the One-time Inspection Program for managing loss of material due to pitting, crevice, microbiologically influence corrosion for these components. The staff reviewed the Lubricating Oil Analysis Program and the One-Time Inspection Program and its evaluations are documented in SER Sections 3.0.3.2.18 and 3.0.3.2.14 respectively. The staff finds that these programs 1) provide for periodic sampling of lubricating oil to maintaincontaminants at acceptable limits to preclude loss of material due to pitting, crevice and microbiologically-influenced corrosion and 2) will perform one-time inspections of selectcomponents exposed to lubricating oil for loss of material due to pitting, crevice and microbiologically-influenced corrosion to verify the effectiveness of the Lubricating Oil Analysis program. The staff noted that one-time inspection is an acceptable method to determine whether or not loss of material is occurring slowly such that the intended function will be maintained during the period of extended operation. On this basis, the staff finds that the Lubricating Oil Analysis Program and the One-Time Inspection Program are adequate to manage loss of material due to pitting, crevice, and microbiol}}

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