ML12233A691
| ML12233A691 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 06/30/2011 |
| From: | Office of Nuclear Reactor Regulation |
| To: | Atomic Safety and Licensing Board Panel |
| SECY RAS | |
| References | |
| RAS 23330, 50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01 | |
| Download: ML12233A691 (51) | |
Text
ENT000536 Submitted: August 20, 2012 NUREG-2101 Safety Evaluation Report Related to the License Renewal of Salem Nuclear Generating Station Docket Numbers 50-272 and 50-311 PSEG Nuclear, LLC Office of Nuclear Reactor Regulation
AVAILABILITY OF REFERENCE MATERIALS IN NRC PUBLICATIONS NRC Reference Material Non-NRC Reference Material As of November 1999, you may electronically access Documents available from public and special technical NUREG-series publications and other NRC records at libraries include all open literature items, such as NRC=s Public Electronic Reading Room at books, journal articles, and transactions, Federal http://www.nrc.gov/reading-rm.html. Register notices, Federal and State legislation, and Publicly released records include, to name a few, congressional reports. Such documents as theses, NUREG-series publications; Federal Register notices; dissertations, foreign reports and translations, and applicant, licensee, and vendor documents and non-NRC conference proceedings may be purchased correspondence; NRC correspondence and internal from their sponsoring organization.
memoranda; bulletins and information notices; inspection and investigative reports; licensee event reports; and Commission papers and their Copies of industry codes and standards used in a attachments. substantive manner in the NRC regulatory process are maintained atC NRC publications in the NUREG series, NRC The NRC Technical Library regulations, and Title 10, Energy, in the Code of Two White Flint North Federal Regulations may also be purchased from one 11545 Rockville Pike of these two sources. Rockville, MD 20852B2738
- 1. The Superintendent of Documents U.S. Government Printing Office Mail Stop SSOP These standards are available in the library for Washington, DC 20402B0001 reference use by the public. Codes and standards are Internet: bookstore.gpo.gov usually copyrighted and may be purchased from the Telephone: 202-512-1800 originating organization or, if they are American Fax: 202-512-2250 National Standards, fromC
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decisions under Section 2.206 of NRC=s regulations (NUREGB0750).
NUREG-2101 Safety Evaluation Report Related to the License Renewal of Salem Nuclear Generating Station Docket Numbers 50-272 and 50-311 PSEG Nuclear, LLC Manuscript Completed: June 2011 Date Published: June 2011 Office of Nuclear Reactor Regulation
ABSTRACT This safety evaluation report (SER) documents the technical review of the Salem Nuclear Generating Station, Units 1 and 2, (Salem) license renewal application (LRA) by the U.S.
Nuclear Regulatory Commission (NRC) staff (the staff). By letter dated August 18, 2009, PSEG Nuclear, LLC (PSEG 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. PSEG requests renewal of the operating licenses (Facility Operating License Numbers DPR-70 and DPR-75) for a period of 20 years beyond the current expiration at midnight August 13, 2016, for Unit 1, and at midnight on April 18, 2020, for Unit 2.
Salem is located approximately 40 miles from Philadelphia, PA, and 8 miles from Salem, NJ.
The NRC issued the construction permits for Unit 1 and Unit 2 on August 25, 1968. The NRC issued the operating license for Unit 1 on December 1, 1976, and for Unit 2 on May 20, 1981.
Both units are pressurized water reactors that were designed and supplied by Westinghouse.
License Amendment Nos. 243 (Salem Unit 1) and 224 (Salem Unit 2), dated May 25, 2001, authorized a 1.4 percent increase in the licensed rated power level of each unit to 3,459 megawatt thermal (MWt).
This SER presents the status of the staffs review of information submitted through May 18, 2011, the cutoff date for consideration in this SER. The staff has resolved all issues associated with requests for additional information and closed all open items since publishing the SER with Open Items. The staff did not identify any new open items that must be resolved before any final determination can be made on the LRA.
iii
TABLE OF CONTENTS ABSTRACT .............................................................................................................................. iii TABLE OF CONTENTS ............................................................................................................v LIST OF TABLES ................................................................................................................... xiii ABBREVIATIONS ................................................................................................................... xv SECTION 1 INTRODUCTION AND GENERAL DISCUSSION ............................................ 1-1 1.1 Introduction .................................................................................................................. 1-1 1.2 License Renewal Background ..................................................................................... 1-2 1.2.1 Safety Review ....................................................................................................... 1-3 1.2.2 Environmental Review .......................................................................................... 1-4 1.3 Principal Review Matters ............................................................................................. 1-5 1.4 Interim Staff Guidance ................................................................................................. 1-6 1.5 Summary of the Open Items ........................................................................................ 1-7 1.6 Summary of Confirmatory Items .................................................................................. 1-9 1.7 Summary of Proposed License Conditions ................................................................ 1-10 SECTION 2 STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW ................................................................................ 2-1 2.1 Scoping and Screening Methodology .......................................................................... 2-1 2.1.1 Introduction ........................................................................................................... 2-1 2.1.2 Summary of Technical Information in the Application ............................................ 2-1 2.1.3 Scoping and Screening Program Review .............................................................. 2-2 2.1.3.1 Implementing Procedures and Documentation Sources Used for Scoping and Screening ................................................................................................ 2-3 2.1.3.2 Quality Controls Applied to LRA Development ................................................ 2-6 2.1.3.3 Training .......................................................................................................... 2-6 2.1.3.4 Scoping and Screening Program Review Conclusion ..................................... 2-7 2.1.4 Plant Systems, Structures, and Components Scoping Methodology ..................... 2-7 2.1.4.1 Application of the Scoping Criteria in 10 CFR 54.4(a)(1) ................................. 2-8 2.1.4.2 Application of the Scoping Criteria in 10 CFR 54.4(a)(2) ............................... 2-13 2.1.4.3 Application of the Scoping Criteria in 10 CFR 54.4(a)(3) ............................... 2-17 2.1.4.4 Plant-Level Scoping of Systems and Structures ........................................... 2-21 2.1.4.5 Mechanical Component Scoping .................................................................. 2-23 2.1.4.6 Structural Component Scoping ..................................................................... 2-24 2.1.4.7 Electrical Component Scoping ...................................................................... 2-26 2.1.4.8 Scoping Methodology Conclusion ................................................................. 2-27 2.1.5 Screening Methodology ...................................................................................... 2-27 2.1.5.1 General Screening Methodology................................................................... 2-27 2.1.5.2 Mechanical Component Screening ............................................................... 2-28 2.1.5.3 Structural Component Screening .................................................................. 2-30 2.1.5.4 Electrical Component Screening ................................................................... 2-31 v
Table of Contents 2.1.5.5 Screening Methodology Conclusion .............................................................. 2-32 2.1.6 Summary of Evaluation Findings ......................................................................... 2-32 2.2 Plant-Level Scoping Results ...................................................................................... 2-33 2.2.1 Introduction ......................................................................................................... 2-33 2.2.2 Summary of Technical Information in the Application .......................................... 2-33 2.2.3 Staff Evaluation ................................................................................................... 2-33 2.2.4 Conclusion .......................................................................................................... 2-34 2.3 Scoping and Screening Results: Mechanical Systems .............................................. 2-35 2.3.1 Reactor Vessel, Internals, and Reactor Coolant System ..................................... 2-36 2.3.1.1 Reactor Coolant System ............................................................................... 2-36 2.3.1.2 Reactor Vessel ............................................................................................. 2-36 2.3.1.3 Reactor Vessel Internals ............................................................................... 2-37 2.3.1.4 SGs .............................................................................................................. 2-38 2.3.2 Engineered Safety Features................................................................................ 2-38 2.3.2.1 Containment Spray System .......................................................................... 2-39 2.3.2.2 Residual Heat Removal System ................................................................... 2-39 2.3.2.3 Safety Injection System ................................................................................ 2-40 2.3.3 Auxiliary Systems ................................................................................................ 2-40 2.3.3.1 Auxiliary Building Ventilation System ............................................................ 2-41 2.3.3.2 Chemical and Volume Control System.......................................................... 2-42 2.3.3.3 Chilled Water System ................................................................................... 2-42 2.3.3.4 Circulating Water System ............................................................................. 2-45 2.3.3.5 Component Cooling System ......................................................................... 2-46 2.3.3.6 Compressed Air System ............................................................................... 2-47 2.3.3.7 Containment Ventilation System ................................................................... 2-48 2.3.3.8 Control Area Ventilation System ................................................................... 2-48 2.3.3.9 Cranes and Hoists ........................................................................................ 2-49 2.3.3.10 Demineralized Water System ..................................................................... 2-50 2.3.3.11 Emergency Diesel Generator and Auxiliaries System ................................. 2-50 2.3.3.12 Fire Protection System ............................................................................... 2-51 2.3.3.13 Fresh Water System ................................................................................... 2-57 2.3.3.14 Fuel Handling and Fuel Storage System ..................................................... 2-58 2.3.3.15 Fuel Handling Ventilation System ............................................................... 2-58 2.3.3.16 Fuel Oil System .......................................................................................... 2-59 2.3.3.17 Heating Water and Heating Steam System ................................................. 2-60 2.3.3.18 Non-radioactive Drain System .................................................................... 2-60 2.3.3.19 Radiation Monitoring System ...................................................................... 2-61 2.3.3.20 Radioactive Drain System........................................................................... 2-61 2.3.3.21 Radwaste System ....................................................................................... 2-63 2.3.3.22 Sampling System ........................................................................................ 2-64 2.3.3.23 Service Water System ................................................................................ 2-65 2.3.3.24 Service Water Ventilation System ............................................................... 2-67 2.3.3.25 Spent Fuel Cooling System ........................................................................ 2-68 2.3.3.26 Switchgear and Penetration Area Ventilation System ................................. 2-69 2.3.4 Steam and Power Conversion Systems .............................................................. 2-70 2.3.4.1 Auxiliary Feedwater System ......................................................................... 2-70 2.3.4.2 Main Condensate and Feedwater System .................................................... 2-70 2.3.4.3 Main Condenser and Air Removal System ................................................... 2-71 2.3.4.4 Main Steam System...................................................................................... 2-72 2.3.4.5 Main Turbine and Auxiliaries System ............................................................ 2-72 2.4 Scoping and Screening Results: Structures .............................................................. 2-74 vi
Table of Contents 2.4.1 Auxiliary Building ................................................................................................. 2-75 2.4.1.1 Summary of Technical Information in the Application.................................... 2-75 2.4.1.2 Conclusion .................................................................................................... 2-75 2.4.2 Component Supports Commodity Group............................................................. 2-76 2.4.2.1 Summary of Technical Information in the Application.................................... 2-76 2.4.2.2 Conclusion .................................................................................................... 2-76 2.4.3 Containment Structure ........................................................................................ 2-77 2.4.3.1 Summary of Technical Information in the Application.................................... 2-77 2.4.3.2 Conclusion .................................................................................................... 2-77 2.4.4 Fire Pump House ................................................................................................ 2-77 2.4.4.1 Summary of Technical Information in the Application.................................... 2-77 2.4.4.2 Staff Evaluation ............................................................................................ 2-78 2.4.4.3 Conclusion .................................................................................................... 2-78 2.4.5 Fuel Handling Building ........................................................................................ 2-79 2.4.5.1 Summary of Technical Information in the Application.................................... 2-79 2.4.5.2 Conclusion .................................................................................................... 2-79 2.4.6 Office Buildings ................................................................................................... 2-79 2.4.6.1 Summary of Technical Information in the Application.................................... 2-79 2.4.6.2 Conclusion .................................................................................................... 2-80 2.4.7 Penetration Areas ............................................................................................... 2-80 2.4.7.1 Summary of Technical Information in the Application.................................... 2-80 2.4.7.2 Conclusion .................................................................................................... 2-80 2.4.8 Pipe Tunnel ......................................................................................................... 2-81 2.4.8.1 Summary of Technical Information in the Application.................................... 2-81 2.4.8.2 Conclusion .................................................................................................... 2-81 2.4.9 Piping and Component Insulation Commodity Group .......................................... 2-81 2.4.9.1 Summary of Technical Information in the Application.................................... 2-81 2.4.9.2 Conclusion .................................................................................................... 2-81 2.4.10 Station Blackout Yard Buildings ........................................................................ 2-82 2.4.10.1 Summary of Technical Information in the Application .................................. 2-82 2.4.10.2 Conclusion .................................................................................................. 2-82 2.4.11 Service Building ................................................................................................ 2-82 2.4.11.1 Summary of Technical Information in the Application .................................. 2-82 2.4.11.2 Conclusion .................................................................................................. 2-83 2.4.12 Service Water Accumulator Enclosures ............................................................ 2-83 2.4.12.1 Summary of Technical Information in the Application .................................. 2-83 2.4.12.2 Staff Evaluation .......................................................................................... 2-83 2.4.12.3 Conclusion .................................................................................................. 2-84 2.4.13 Service Water Intake ......................................................................................... 2-84 2.4.13.1 Summary of Technical Information in the Application .................................. 2-84 2.4.13.2 Conclusion .................................................................................................. 2-84 2.4.14 Shoreline Protection and Dike ........................................................................... 2-85 2.4.14.1 Summary of Technical Information in the Application .................................. 2-85 2.4.14.2 Staff Evaluation .......................................................................................... 2-85 2.4.14.3 Conclusion .................................................................................................. 2-85 2.4.15 Switchyard ........................................................................................................ 2-86 2.4.15.1 Summary of Technical Information in the Application .................................. 2-86 2.4.15.2 Conclusion .................................................................................................. 2-86 2.4.16 Turbine Building ................................................................................................ 2-86 2.4.16.1 Summary of Technical Information in the Application .................................. 2-86 2.4.16.2 Conclusion .................................................................................................. 2-87 vii
Table of Contents 2.4.17 Yard Structures ................................................................................................. 2-87 2.4.17.1 Summary of Technical Information in the Application .................................. 2-87 2.4.17.2 Conclusion .................................................................................................. 2-87 2.5 Scoping and Screening Results: Electrical and Instrumentation and Controls Systems..................................................................................................................... 2-88 2.5.1 Electrical and Instrumentation and Controls Component Commodity Groups...... 2-88 2.5.1.1 Summary of Technical Information in the Application.................................... 2-88 2.5.1.2 Staff Evaluation ............................................................................................ 2-89 2.5.1.3 Conclusion .................................................................................................... 2-90 2.6 Conclusion for Scoping and Screening ...................................................................... 2-91 SECTION 3 AGING MANAGEMENT REVIEW RESULTS .................................................. 3-1 3.0 Applicants Use of the Generic Aging Lessons Learned Report ................................... 3-1 3.0.1 Format of the License Renewal Application .......................................................... 3-2 3.0.1.1 Overview of Table 1s ...................................................................................... 3-2 3.0.1.2 Overview of Table 2s ...................................................................................... 3-3 3.0.2 Staffs Review Process ......................................................................................... 3-4 3.0.2.1 Review of AMPs ............................................................................................. 3-4 3.0.2.2 Review of AMR Results .................................................................................. 3-6 3.0.2.3 UFSAR Supplement ....................................................................................... 3-6 3.0.2.4 Documentation and Documents Reviewed ..................................................... 3-6 3.0.3 Aging Management Programs ............................................................................... 3-6 3.0.3.1 AMPs That Are Consistent with the GALL Report ......................................... 3-11 3.0.3.2 AMPS That Are Consistent with the GALL Report with Exceptions or Enhancements .............................................................................................. 3-77 3.0.3.3 AMPs That Are Not Consistent with or Not Addressed in the GALL Report......................................................................................................... 3-188 3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs .......................................................................................................... 3-221 3.0.4.1 Summary of Technical Information in Application ....................................... 3-221 3.0.4.2 Staff Evaluation .......................................................................................... 3-221 3.0.4.3 Conclusion .................................................................................................. 3-222 3.1 Aging Management of Reactor Vessel, Internals, and Reactor Coolant System ...... 3-223 3.1.1 Summary of Technical Information in the Application ........................................ 3-223 3.1.2 Staff Evaluation ................................................................................................. 3-223 3.1.2.1 AMR Results That Are Consistent with the GALL Report ............................ 3-244 3.1.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended .......................................................... 3-259 3.1.2.3 AMR Results That Are Not Consistent With or Not Addressed in the GALL Report............................................................................................... 3-285 3.1.3 Conclusion ........................................................................................................ 3-291 3.2 Aging Management of Engineered Safety Features ................................................. 3-292 3.2.1 Summary of Technical Information in the Application ........................................ 3-292 3.2.2 Staff Evaluation ................................................................................................. 3-292 3.2.2.1 AMR Results That Are Consistent with the GALL Report ............................ 3-303 3.2.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation Is Recommended .......................................................... 3-313 3.2.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report............................................................................................... 3-321 3.2.3 Conclusion ........................................................................................................ 3-323 viii
Table of Contents 3.3 Aging Management of Auxiliary Systems ................................................................. 3-324 3.3.1 Summary of Technical Information in the Application ........................................ 3-324 3.3.2 Staff Evaluation ................................................................................................. 3-325 3.3.2.1 AMR Results That Are Consistent with the GALL Report ............................ 3-344 3.3.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended .......................................................... 3-370 3.3.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report............................................................................................... 3-399 3.3.3 Conclusion ........................................................................................................ 3-422 3.4 Aging Management of Steam and Power Conversion Systems ............................... 3-423 3.4.1 Summary of Technical Information in the Application ........................................ 3-423 3.4.2 Staff Evaluation ................................................................................................. 3-423 3.4.2.1 AMR Results That Are Consistent with the GALL Report ............................ 3-431 3.4.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended .......................................................... 3-436 3.4.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report............................................................................................... 3-448 3.4.3 Conclusion ........................................................................................................ 3-450 3.5 Aging Management of Containments, Structures, and Component Supports ........... 3-451 3.5.1 Summary of Technical Information in the Application ........................................ 3-451 3.5.2 Staff Evaluation ................................................................................................. 3-451 3.5.2.1 AMR Results That Are Consistent with the GALL Report ............................ 3-468 3.5.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation Is Recommended .......................................................... 3-488 3.5.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report............................................................................................... 3-517 3.5.3 Conclusion ........................................................................................................ 3-540 3.6 Aging Management of Electrical and Instrumentation and Controls ......................... 3-541 3.6.1 Summary of Technical Information in the Application ........................................ 3-541 3.6.2 Staff Evaluation ................................................................................................. 3-541 3.6.2.1 AMR Results That Are Consistent with the GALL Report ............................ 3-545 3.6.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended .......................................................... 3-547 3.6.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report............................................................................................... 3-550 3.6.3 Conclusion ........................................................................................................ 3-553 3.7 Conclusion for Aging Management Review Results ................................................. 3-554 SECTION 4 TIME-LIMITED AGING ANALYSES................................................................. 4-1 4.1 Identification of Time-Limited Aging Analyses .............................................................. 4-1 4.1.1 Summary of Technical Information in the Application ............................................ 4-1 4.1.2 Staff Evaluation ..................................................................................................... 4-2 4.1.3 Conclusion ............................................................................................................ 4-4 4.2 Reactor Vessel Neutron Embrittlement ........................................................................ 4-5 4.2.1 Neutron Fluence Analysis ..................................................................................... 4-5 4.2.1.1 Summary of Technical Information in the Application...................................... 4-5 4.2.1.2 Staff Evaluation .............................................................................................. 4-6 4.2.1.3 UFSAR Supplement ....................................................................................... 4-7 4.2.1.4 Conclusion ...................................................................................................... 4-7 4.2.2 Upper-Shelf Energy Analyses ............................................................................... 4-7 ix
Table of Contents 4.2.2.1 Summary of Technical Information in the Application...................................... 4-7 4.2.2.2 Staff Evaluation .............................................................................................. 4-7 4.2.2.3 UFSAR Supplement ....................................................................................... 4-9 4.2.2.4 Conclusion ...................................................................................................... 4-9 4.2.3 Pressurized Thermal Shock Analyses ................................................................... 4-9 4.2.3.1 Summary of Technical Information in the Application...................................... 4-9 4.2.3.2 Staff Evaluation ............................................................................................ 4-10 4.2.3.3 UFSAR Supplement ..................................................................................... 4-11 4.2.3.4 Conclusion .................................................................................................... 4-12 4.2.4 Reactor Vessel Pressure-Temperature Limits, Including Low Temperature Overpressurization Protection Limits ................................................................... 4-12 4.2.4.1 Summary of Technical Information in the Application.................................... 4-12 4.2.4.2 Staff Evaluation ............................................................................................ 4-12 4.2.4.3 UFSAR Supplement ..................................................................................... 4-13 4.2.4.4 Conclusion .................................................................................................... 4-13 4.3 Metal Fatigue of Piping and Components .................................................................. 4-14 4.3.1 Nuclear Steam Supply System Pressure Vessel and Component Fatigue Analyses ................................................................................................ 4-14 4.3.1.1 Summary of Technical Information in the Application.................................... 4-14 4.3.1.2 Staff Evaluation ............................................................................................ 4-15 4.3.1.3 UFSAR Supplement ..................................................................................... 4-17 4.3.1.4 Conclusion .................................................................................................... 4-17 4.3.2 Pressurizer Safety Valve and Pilot-Operated Relief Valve Fatigue Analyses....... 4-17 4.3.2.1 Pressurizer Safety Valve............................................................................... 4-17 4.3.2.2 Pressurizer Pilot-Operated Relief Valve Fatigue Analyses ............................ 4-19 4.3.3 American Standards Association/United States of America Standards B31.1 Piping Fatigue Analyses...................................................................................... 4-21 4.3.3.1 Summary of Technical Information in the Application.................................... 4-21 4.3.3.2 Staff Evaluation ............................................................................................ 4-21 4.3.3.3 UFSAR Supplement ..................................................................................... 4-21 4.3.3.4 Conclusion .................................................................................................... 4-22 4.3.4 Supplementary ASME Code Section III, Class 1 Piping and Component Fatigue Analyses ................................................................................................ 4-22 4.3.4.1 NRC Bulletin 88-08, Thermal Stresses in Piping Connected to Reactor Coolant Systems........................................................................................... 4-22 4.3.4.2 NRC Bulletin 88-11, Pressurizer Surge Line Thermal Stratification ............... 4-23 4.3.4.3 Salem Unit 1 Steam Generator Feedwater Nozzle Transition Piece ............. 4-25 4.3.4.4 Salem Unit 1 Steam Generator Primary Manway Studs ................................ 4-26 4.3.5 Reactor Vessel Internals Fatigue Analyses ......................................................... 4-28 4.3.5.1 Summary of Technical Information in the Application.................................... 4-28 4.3.5.2 Staff Evaluation ............................................................................................ 4-28 4.3.5.3 UFSAR Supplement ..................................................................................... 4-29 4.3.5.4 Conclusion .................................................................................................... 4-29 4.3.6 Spent Fuel Pool Bottom Plates Fatigue Analyses ............................................... 4-29 4.3.6.1 Summary of Technical Information in the Application.................................... 4-29 4.3.6.2 Staff Evaluation ............................................................................................ 4-29 4.3.6.3 UFSAR Supplement ..................................................................................... 4-30 4.3.6.4 Conclusion .................................................................................................... 4-30 4.3.7 Environmentally-Assisted Fatigue Analyses ........................................................ 4-31 4.3.7.1 Summary of Technical Information in the Application.................................... 4-31 4.3.7.2 Staff Evaluation ............................................................................................ 4-31 x
Table of Contents 4.3.7.3 UFSAR Supplement ..................................................................................... 4-37 4.3.7.4 Conclusion .................................................................................................... 4-37 4.4 Other Plant-Specific Analyses.................................................................................... 4-38 4.4.1 Reactor Vessel Underclad Cracking Analyses .................................................... 4-38 4.4.1.1 Summary of Technical Information in the Application.................................... 4-38 4.4.1.2 Staff Evaluation ............................................................................................ 4-38 4.4.1.3 UFSAR Supplement ..................................................................................... 4-39 4.4.1.4 Conclusion .................................................................................................... 4-39 4.4.2 Reactor Coolant Pump Flywheel Fatigue Crack Growth Analyses ...................... 4-39 4.4.2.1 Summary of Technical Information in the Application.................................... 4-39 4.4.2.2 Staff Evaluation ............................................................................................ 4-39 4.4.2.3 UFSAR Supplement ..................................................................................... 4-41 4.4.2.4 Conclusion .................................................................................................... 4-41 4.4.3 Leak-Before-Break Analyses ............................................................................... 4-41 4.4.3.1 Summary of Technical Information in the Application.................................... 4-41 4.4.3.2 Staff Evaluation ............................................................................................ 4-42 4.4.3.3 UFSAR Supplement ..................................................................................... 4-48 4.4.3.4 Conclusion .................................................................................................... 4-49 4.4.4 Applicability of ASME Code Case N-481 to the Salem Units 1 and 2 Reactor Coolant Pump Casings ....................................................................................... 4-49 4.4.4.1 Summary of Technical Information in the Application.................................... 4-49 4.4.4.2 Staff Evaluation ............................................................................................ 4-49 4.4.4.3 UFSAR Supplement ..................................................................................... 4-51 4.4.4.4 Conclusion .................................................................................................... 4-51 4.4.5 Salem Unit 1 Volume Control Tank Flaw Growth Analysis .................................. 4-51 4.4.5.1 Summary of Technical Information in the Application.................................... 4-51 4.4.5.2 Staff Evaluation ............................................................................................ 4-52 4.4.5.3 UFSAR Supplement ..................................................................................... 4-54 4.4.5.4 Conclusion .................................................................................................... 4-54 4.5 Fuel Transfer Tube Bellows Design Cycles................................................................ 4-55 4.5.1 Summary of Technical Information in the Application .......................................... 4-55 4.5.2 Staff Evaluation ................................................................................................... 4-55 4.5.3 UFSAR Supplement ............................................................................................ 4-56 4.5.4 Conclusion .......................................................................................................... 4-56 4.6 Crane Load Cycle Limits ............................................................................................ 4-57 4.6.1 Polar Gantry Crane ............................................................................................. 4-57 4.6.1.1 Summary of Technical Information in the Application.................................... 4-57 4.6.1.2 Staff Evaluation ............................................................................................ 4-57 4.6.1.3 UFSAR Supplement ..................................................................................... 4-58 4.6.1.4 Conclusion .................................................................................................... 4-58 4.6.2 Fuel Handling Crane ........................................................................................... 4-59 4.6.2.1 Summary of Technical Information in the Application.................................... 4-59 4.6.2.2 Staff Evaluation ............................................................................................ 4-59 4.6.2.3 UFSAR Supplement ..................................................................................... 4-59 4.6.2.4 Conclusion .................................................................................................... 4-59 4.6.3 Cask Handling Crane .......................................................................................... 4-60 4.6.3.1 Summary of Technical Information in the Application.................................... 4-60 4.6.3.2 Staff Evaluation ............................................................................................ 4-60 4.6.3.3 UFSAR Supplement ..................................................................................... 4-60 4.6.3.4 Conclusion .................................................................................................... 4-60 4.7 Environmental Qualification of Electrical Equipment .................................................. 4-61 xi
Table of Contents 4.7.1 Summary of Technical Information in the Application .......................................... 4-61 4.7.2 Staff Evaluation ................................................................................................... 4-61 4.7.3 UFSAR Supplement ............................................................................................ 4-62 4.7.4 Conclusion .......................................................................................................... 4-62 4.8 Conclusion ................................................................................................................. 4-63 SECTION 5 REVIEW BY THE ADVISORY COMMITTEE ON REACTOR SAFEGUARDS ................................................................................................ 5-1 SECTION 6 CONCLUSION................................................................................................. 6-1 APPENDIX A SALEM NUCLEAR GENERATING STATION LICENSE RENEWAL COMMITMENTS ................................................................................................................... A-1 APPENDIX B CHRONOLOGY ............................................................................................ B-1 APPENDIX C PRINCIPAL CONTRIBUTORS .....................................................................C-1 APPENDIX D REFERENCES .............................................................................................D-1 xii
Introduction and General Discussion 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 four proposed license conditions.
The first license condition requires the applicant to update the UFSAR supplement required by 10 CFR 54.21(d) in the UFSAR 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 operation are complete and can be verified by NRC inspection.
The third license condition requires that all capsules in the reactor vessel that are removed and tested must meet the test procedures and reporting requirements of ASTM E 185-82 to the extent practicable for the configuration of the specimens in the capsule. Any changes to the capsule withdrawal schedule, including spare capsules, must be approved by the NRC prior to implementation. All capsules placed in storage must be maintained for future insertion. Any changes to storage requirements must be approved by the NRC.
The fourth license condition requires the applicant to take one core sample in the Unit 1 SFP west wall, by the end of 2013, and one core sample in the east wall where there have been indications of borated water ingress through the concrete, by the end of 2015. The core samples (east and west walls) will expose the rebar, which will be examined for signs of corrosion. Any sample showing signs of concrete degradation and/or rebar corrosion will be entered into the licensees corrective action program for further evaluation. The licensee shall submit a report in accordance with 10 CFR 50.4 no later than three months after each sample is taken on the results, recommendations, and any additional planned actions.
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Aging Management Review Results Cracking Due to Stress Corrosion Cracking, Primary Water Stress Corrosion Cracking, and Irradiation-Assisted Stress Corrosion Cracking. Therefore, the staff issued RAI 3.1.2.2.12-1 requesting that the applicant provide a revised LRA Table 3.1.2-3 to identify the aging effect discussed in LRA Section 3.1.2.2.17, or justify combining LRA Sections 3.1.2.2.12 and 3.1.2.2.17 under the table column title Aging Effect Requiring Management in LRA Table 3.1.2-3.
Although the response, dated July 15, 2010, to RAI 3.1.2.2.12-1 did not provide direct justification, the staff determines that the proposed industry program for managing PWR internals as documented in MRP-227 is structured around components, not around aging effects. Therefore, not identifying PWSCC as an aging effect for certain components in LRA Table 3.1.2-3 has no impact on the AMP to be implemented for managing PWR internals.
MRP-227 is currently under the NRCs review in a separate effort. Hence, RAI 3.1.2.2.12-1 is resolved.
Based on a review of the programs identified above, the staff concludes that the applicants programs meet SRP-LR Section 3.1.2.2.12 criteria. For those line items that apply to LRA Section 3.1.2.2.12, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.1.2.2.13 Cracking Due to Primary Water Stress-Corrosion Cracking The staff reviewed LRA Section 3.1.2.2.13 against the criteria in SRP-LR Section 3.1.2.2.13, which recommends no further AMR if the applicant complies with applicable NRC orders and provides a commitment in the UFSAR supplement to implement applicable: (1) bulletins and GLs and (2) staff-accepted industry guidelines. The staff noted that the applicants commitment (Commitment No. 46) in LRA Appendix A, Section A.5 commits to the implementation of the Nickel Alloy Aging Management Program and that various portions of that program contain language which is consistent with the commitment described in SRP-LR Section 3.1.2.2.13.
The staff also notes that all of the AMR results lines that refer to Table 3.1.1, item 3.1.1-31 are aligned with the applicants commitment as described in LRA Appendix A, Section A.5. The staff finds the applicants proposal acceptable because the applicant provided the appropriate commitment in the UFSAR supplement and the AMR results lines refer to the commitment.
3.1.2.2.14 Wall Thinning Due to Flow-Accelerated Corrosion LRA Section 3.1.2.2.14 refers to Table 3.1.1, item 3.1.1-32 and addresses the steel SG feedwater inlet ring and supports exposed to treated water, which are being managed for wall thinning due to flow-accelerated corrosion by the Steam Generator Tube Integrity Program. In LRA Table 3.1.1, item 3.1.1-32 and LRA Section 3.1.2.2.14, the applicant stated that the Steam Generator Tube Integrity Program will be used to manage wall thinning in the feedwater inlet ring and supports. The applicant further stated that the Steam Generator Tube Integrity Program implements a number of industry guidelines and incorporates a balance of prevention, inspection, evaluation, repair, and leakage monitoring measures to assure that existing environmental conditions are not causing wall thinning that could result in loss of component intended function.
The staff reviewed LRA Section 3.1.2.2.14 against the criteria in SRP-LR Section 3.1.2.2.14, which state that wall thinning due to flow-accelerated corrosion could occur in the steel 3-276
Aging Management Review Results feedwater inlet rings and supports. The GALL Report refers to NRC IN 91-19, Steam Generator Feedwater Distribution Piping Damage, for evidence of flow-accelerated corrosion in SGs 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 staff reviewed the applicants Steam Generator Tube Integrity Program and its evaluation is documented in SER Section 3.0.3.1.8. In its review of components associated with LRA item 3.1.1-32, the staff noted that the GALL Report recommends that a plant-specific AMP be evaluated and the applicant credits the Steam Generator Tube Integrity Program to manage wall thinning in these components.
The staff noted that the Steam Generator Tube Integrity Program description in LRA Section B.2.1.10 states that the program includes managing the aging effect of wall thinning.
However, the LRA does not describe what inspection or analytical techniques are used to ensure that excessive wall thinning in components does not occur.
By letter dated June 29, 2010, the staff issued RAI 3.1.2.2.14-01 requesting that the applicant describe its examination techniques and evaluation methodology used to manage wall thinning in the SG feedwater inlet rings and supports.
In its response to the RAI, dated July 28, 2010, the applicant stated that the Steam Generator Tube Integrity Program uses visual inspections of the SGs secondary-side internals and that it does not include predictive analytical techniques. The applicant further stated that the Unit 1 SGs are Westinghouse Model F, with feedwater rings and supports constructed of carbon steel, and that the Unit 2 SGs are AREVA Model 61/19T, with feedwater ring supports constructed of low-alloy steel plates and feedwater rings constructed of 316L stainless steel. The applicant also stated that the aging effect and mechanism of wall thinning due to flow-accelerated corrosion does not apply to the stainless steel Unit 2 SG feedwater ring.
The applicant stated that the visual inspection techniques and associated acceptance criteria are determined by a SG degradation assessment which evaluates internal and external operating experience, industry guidance, design features, and materials of construction. The applicant stated that these inspections identify the general condition of the applicable SG components and inspect for evidence of erosion-corrosion, irregular geometry, and structural changes and that the acceptance criteria require that there be no visible signs of deterioration in the Unit 1 feedwater rings or in the Units 1 and 2 feedwater ring supports. The applicant further stated that it performs an operational assessment in accordance with NEI 97-06, Steam Generator Program Guidelines, and applicable EPRI documents to confirm that acceptance criteria are met for the SGs to return to service and operate for the subsequent cycle and that the operational assessment ensures that deficiencies are identified and corrective actions are taken before loss of component intended function occurs. The applicant also stated that while preparing its response, it noted that LRA Table 3.1.2-4, Summary of Aging Management Evaluations for SGs, did not correctly include the material differences between Unit 1 feedwater rings (carbon steel) and Unit 2 feedwater rings (stainless steel). The applicant revised this table to show that wall thinning due to flow-accelerated corrosion is applicable for the Unit 1 carbon steel feedwater rings and for the Units 1 and 2 carbon steel or low-alloy steel supports, but is not applicable for the Unit 2 stainless steel feedwater rings. In subsequent letters dated August 26, 2010, and October 8, 2010, the applicant further revised LRA Table 3.1.2-4 to state that its SG designs include both carbon steel and stainless steel secondary internals and that wall thinning due to flow-accelerated corrosion is also applicable for the carbon steel SG secondary internals. The applicant stated that these carbon steel and low-alloy steel 3-277
Aging Management Review Results components are in a treated water environment (secondary feedwater/steam) and the aging effect will be managed by the Steam Generator Tube Integrity Program. The applicant also added lines showing that loss of material due to pitting and crevice corrosion and cracking due to SCC are aging effects applicable for the Unit 2 stainless steel feedwater rings. These stainless steel components are in a treated water environment and those aging effects will be managed by a combination of the Water Chemistry Program and the Steam Generator Tube Integrity Program.
In its review of the applicants response, the staff noted that GALL AMP XI.M19, Steam Generator Tube Integrity, references NEI 97-06. The staff determined that NEI 97-06 provides acceptable guidance for inspection and assessment of additional SG components, including the feedwater rings, supports, and secondary internals, consistent with the GALL Report. The staff further noted that industry operating experience supports the applicants claim that flow-accelerated corrosion is not applicable to the Unit 2 stainless steel feedwater rings and the secondary internals. The staff finds the Steam Generator Tube Integrity Program acceptable to manage aging of the Unit 1 carbon steel feedwater rings and supports, the Unit 2 low-alloy steel feedwater ring supports, and the carbon steel secondary internals because the program:
(1) provides visual inspections of the subject SG components based on recommendations of NEI 97-06, (2) includes assessments of inspection results against appropriate acceptance criteria, and (3) provides for corrective actions to be taken, as needed, to ensure that the subject components remain capable of performing their intended functions between scheduled SG inspections.
The staff finds the applicants change to LRA Table 3.1.2-4 acceptable because these changes:
(1) document the material difference between the steel feedwater rings in Unit 1 and the stainless steel feedwater rings in Unit 2 and (2) for the stainless steel feedwater rings and secondary internals, the staff has determined that the applicants AMR results are acceptable as documented in SER Sections 3.4.2.2.6 and 3.4.2.2.7 for LRA Table 3.4.1, items 3.4.1-14 and 3.4.1-16, respectively.
Based on its review, the staff finds the applicants response to RAI 3.1.2.2.14-01 acceptable as described above. The staffs concern described in RAI 3.1.2.2.14-01 is resolved.
Based on the program identified above, the staff concludes that the applicants program meets 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 PWR reactor internal components exposed to reactor coolant as an aging effect that the applicant will manage, consistent with the SRP-LR, by the commitment of the PWR Vessel Internals Program.
SRP-LR Section 3.1.2.2.15 states that:
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Aging Management Review Results Changes in dimensions due to void swelling could occur in stainless steel and nickel alloy PWR reactor internal components exposed to reactor coolant. The GALL Report recommends no further AMR if the applicant provides a commitment in the [U]FSAR Supplement to (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval.
As described in LRA Section 3.1.2.2.15, the applicant made a commitment to incorporate all three GALL Report requirements stated above to manage this aging effect. The PWR Vessel Internals Program contains this commitment (Commitment No. 7). Commitment No. 7 is also identified in UFSAR Section A.2.1.7. Therefore, the staff concludes that the applicants program meets the SRP-LR Section 3.1.2.2.15 criteria. The staff also examined LRA Table 3.1.2-3 to find out whether the RPV internals subjected to these aging effects are consistent with those listed in GALL Report Table IV.B2. The staff confirmed that LRA Table 3.1.2-3 identified all GALL Report Table IV.B2 items and the components under them for this aging effect (IV.B2-1, IV.B2-4, IV.B2-7, IV.B2-11, IV.B2-15, IV.B2-19, IV.B2-23, IV.B2-27, IV.B2-29, IV.B2-35, IV.B2-39, and IV.B2-41). For GALL Report items IV.B2-4, IV.B2-19, and IV.B2-29, the applicant identified additional RPV internal components which are different but consistent with these GALL Report items for material, environment, and aging effect. For most of the GALL Report Table IV.B2 items mentioned above, LRA Table 3.1.2-3 provides a set of subcomponents to represent a single component in GALL Report Table IV.B2. The applicants approach of including additional components under the required AMP for GALL Report items IV.B2-4, IV.B2-19, and IV.B2-29 is acceptable.
Based on a review of the program identified above, the staff concludes that the applicants program meets 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).
3.1.2.2.16 Cracking Due to Stress-Corrosion Cracking and Primary Water Stress-Corrosion Cracking The staff reviewed LRA Section 3.1.2.2.16 against the criteria in SRP-LR Section 3.1.2.2.16.
(1) LRA Section 3.1.2.2.16.1 refers to Table 3.1.1, item 3.1.1-34, and addresses stainless steel and nickel-alloy reactor CRD head penetration pressure housings, which are managed for cracking due to SCC and PWSCC. The LRA states that the applicant will implement the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD and Water Chemistry programs to manage the cracking due to SCC in the stainless steel reactor CRD head penetration pressure housings.
The staff reviewed LRA Section 3.1.2.2.16.1 against the criteria in SRP-LR Section 3.1.2.2.16.1, which state that cracking due to SCC could occur on the primary coolant side of PWR steel SG upper and lower heads, tubesheets, and tube-to-tubesheet welds made or clad with stainless steel. The SRP-LR also states that cracking due to PWSCC could occur on the primary coolant side of PWR steel SG upper 3-279
Aging Management Review Results and lower heads, tubesheets, and tube-to-tubesheet welds made or clad with nickel alloy. The staff noted that the GALL Report recommends the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD and Water Chemistry programs to manage these aging effects. In addition, the GALL Report indicates that no further AMR of nickel alloys are required if the applicant complies with applicable NRC orders and provides a commitment in the UFSAR supplement to implement applicable NRC bulletins, GLs, and NRC staff-accepted industry guidelines.
The staff further reviewed the LRA and identified in Table 3.1.1, item 3.1.1-34, and Table 3.1.2-2 that the applicant addressed SCC of stainless steel reactor CRD head penetration pressure housings exposed to reactor coolant and credited the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD and Water Chemistry programs to manage the aging effect. The staff reviewed the applicants ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD and Water Chemistry programs and its evaluations are documented in SER Sections 3.0.3.1.1 and 3.0.3.1.2, respectively. In its review, the staff finds that the credited programs are adequate to manage the aging effect because: (a) the Water Chemistry Program monitors the plant water chemistry parameters against the established parameter limits and, if a parameter exceeds the limit, the program performs adequate actions such that the water chemistry control continues to mitigate the aging effect; (b) the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program includes inspections of selected components to verify the effectiveness of the Water Chemistry Program consistent with the GALL Report; and (c) the inspections in accordance with ASME Code Section XI can ensure that significant degradation does not occur and the intended function of the component is maintained during the period of extended operation consistent with the GALL Report.
In LRA Table 3.1.1, the applicant further stated that item 3.1.1-35 is not applicable because Salem Units 1 and 2 SGs are not a once-through design and, therefore, do not have the components associated with this model of SGs. The staff noted that the GALL Report, Revision 1, Volume 2 indicates that item 3.1.1-35 is only applicable to OTSGs, but not to recirculating SGs.
UFSAR Section 5.5.2.2.2 describes Unit 1 Model F SG tubes as fabricated from Alloy 600TT and welded to the Inconel cladding on the primary face of the tube plate.
UFSAR Section 5.5.2.2.1 describes Unit 2 replacement SG tubes as fabricated from Alloy 690TT and weld clad with Alloy 600 at the primary side of the tubesheet.
The staff noted that ASME Code Section XI does not require any inspection of the tube-to-tubesheet welds. In addition, no specific NRC orders or bulletins require examination of this weld. However, the staffs concern is that, if the tubesheet cladding is Alloy 600, the autogenous tube-to-tubesheet weld may not have sufficient Chromium content to prevent initiation of PWSCC, even when the SG tubes are made from Alloy 690TT, as it is the configuration for the applicants Unit 2 SG tubes. Consequently, such a PWSCC crack initiated in this region, close to a tube, could propagate into/through the weld, causing a failure of the weld and of the RCPB, even for recirculating SGs such as those for both units. Therefore, unless the NRC has approved a redefinition of the pressure boundary in which the autogenous tube-to-tubesheet weld is no longer included, or the tubesheet cladding and welds are not susceptible to PWSCC, the staff considers that the effectiveness of the primary water chemistry program should be verified to ensure PWSCC does not occur.
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Aging Management Review Results By letter dated November 4, 2010, the staff issued RAI 3.1.1-03 requesting that the applicant clarify for Unit 1 SGs whether the tube-to-tubesheet welds are included in the RCPB or if alternate repair criteria (ARC) have been permanently approved.
Furthermore, the staff noted that if there is no ARC permanently approved, the applicant should provide a plant-specific AMP that will complement the primary water chemistry program in order to verify the effectiveness of the primary water chemistry program and ensure that cracking due to PWSCC is not occurring in tube-to-tubesheet welds. For Unit 2 SGs tube-to-tubesheet welds, the staff requested that the applicant provide either a plant-specific AMP that will complement the primary water chemistry program, in order to verify the effectiveness of the primary water chemistry program and ensure that cracking due to PWSCC is not occurring in tube-to-tubesheet welds, or provide a rationale for why such a program is not needed. The staff identified this as Open Item OI 3.1.2.2.16-1.
In its response dated December 1, 2010, and revised by its letter dated December 15, 2010, the applicant committed to the following:
[It] will develop a plan for each Unit to address the potential for cracking of the primary to secondary pressure boundary due to PWSCC of tube-to-tubesheet welds. Each plan will consist of two options.
The applicant committed in Commitment No. 51 to develop a plan for each unit before the period of extended operation. Each plan consists of two options.
For Unit 1, the applicant stated that the TSs were amended on March 29, 2010 (ADAMS Accession No. ML100570452), approving a one-time change to TS Section 6.8.4.i, Steam Generator Program. The applicant explained that this amendment is an approval for ARC and limits the required inspection (and repair if degradation is found) to the portions of the SG tubes passing through the upper 13.1 inches of the approximate 21-inch tubesheet region; therefore, the bottom 7.9 inches of the tube, including the tube-to-tubesheet weld, are not presently considered part of the RCPB. The applicant further stated that the TS amendment, used in the spring 2010 refueling outage, is valid until the next scheduled SG tube inspections presently scheduled for the spring 2013 refueling outage. Since this ARC approval expires by the spring 2013 refueling outage, which is prior to the Unit 1 period of extended operation, the applicant stated that it would develop a plan to address potential cracking of the SG primary to secondary pressure boundary due to PWSCC of tube-to-tubesheet welds consisting of the following two options:
In the first option, the applicant stated that it would request permanent NRC approval for ARC, which re-defines the RCPB to no longer include the autogenous tube-to-tubesheet welds prior to the Unit 1 period of extended operation. The applicant further stated that if permanent approval for ARC has not been granted by the NRC prior to Unit 1 entering its period of extended operation, it would implement the second option.
In the second option, the applicant stated that it would perform a one-time inspection of a representative number of tube-to-tubesheet welds in each of the four SGs to determine if PWSCC is present and verify the effectiveness of the Water Chemistry Program. The applicant also stated that if weld cracking is identified, the condition would be resolved through repair or engineering evaluation to justify continued service, as appropriate, and a periodic monitoring program would be established to perform routine tube-to-tubesheet inspections for the remaining life of the SGs.
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Aging Management Review Results Moreover, the applicant stated that the SG tube-to-tubesheet welds have been in service for approximately 12 years since the Unit 1 SGs were replaced in April 1998. The applicant further stated that these inspections would be performed between April 2018 and April 2023, such that the SGs will have been in service between 20 and 25 years.
For Unit 2, the applicant stated that the plan would also address potential failure of the SG RCPB due to PWSCC of tube-to-tubesheet welds and would consist of the following two options:
In the first option, the applicant stated that it would perform an analytical evaluation of the SG tube-to-tubesheet welds in order to establish a technical basis for either determining that the tubesheet cladding and welds are not susceptible to PWSCC, or redefining the pressure boundary such that the autogenous tube-to-tubesheet weld is no longer included and, therefore, not required for the RCPB function. The applicant further stated that the redefinition of the RCPB would be submitted as part of a license amendment request requiring approval from the NRC, and the approved analytical evaluation would supersede the need to develop a plant-specific AMP to verify the effectiveness of the Water Chemistry Program.
In the second option, the applicant stated that it would perform a one-time inspection of a representative number of tube-to-tubesheet welds in each of the four SGs to determine if PWSCC is present and verify the effectiveness of the Water Chemistry Program. The applicant also stated that if weld cracking is identified, the condition would be resolved through repair or engineering evaluation to justify continued service, as appropriate, and a periodic monitoring program would be established to perform routine tube-to-tubesheet inspections for the remaining life of the SGs.
Moreover, the applicant stated that the SG tube-to-tubesheet welds for Unit 2 have been in service for less than 3 years since the SGs had been replaced in April 2008. The applicant further stated that these inspections would be performed between April 2028 and April 2033, such that the SGs will have been in service between 20 and 25 years.
Based on its review, the staff finds the applicants response to RAI 3.1.1-03 and associated Commitment No. 51 acceptable because the applicant will manage the aging effect of cracking due to PWSCC in the SG tube-to-tubesheet welds either by demonstrating that those welds are no longer required for the SG RCPB function (or not susceptible to PWSCC for Unit 2), or by implementing a one-time inspection on a representative number of tube-to-tubesheet welds of each SG to determine if PWSCC is present, in a time period consistent with the detection of potential PWSCC cracks. The staff finds that the timing of this inspection for each unit is acceptable because at the time of the inspections, the respective SGs will have been in operation for between 20 and 25 years, and it is unlikely that significant detrimental PWSCC cracking will have initiated. The staff also noted that, in case the aging effect is identified, this one-time inspection would be accompanied by corrective actions, including an evaluation of the degradation and the implementation of routine inspections of the tube-to-tubesheet welds for the remaining life of the SGs. The staffs concern described in RAI 3.1.1-03 is resolved, and Open item OI 3.1.2.2.16-1 is closed.
The staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
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Aging Management Review Results (2) LRA Section 3.1.2.2.16.2 refers to Table 3.1.1, item 3.1.1-36 and addresses the SCC in the stainless steel pressurizer spray head exposed to reactor coolant. The LRA further states that it will implement the Water Chemistry Program and One-Time Inspection Program to manage the aging effect.
The staff reviewed LRA Section 3.1.2.2.16.2 against the criteria in SRP-LR Section 3.1.2.2.16.2, which state that cracking due to SCC could occur on stainless steel pressurizer spray heads. The SRP-LR also states that the existing program relies on control of water chemistry to mitigate this aging effect. The SRP-LR further states that the GALL Report recommends a one-time inspection to confirm that the cracking does not occur. The staff also noted that the GALL Report, item IV.C2-17, recommends the Water Chemistry Program and the One-Time Inspection Program to manage the aging effect of stainless steel components. The staff noted that the GALL Report recommends the One-Time Inspection Program to verify the effectiveness of the water chemistry control program.
The staff reviewed the LRA and identified in Table 3.1.1, item 3.1.1-36, and Table 3.1.2-1 that the applicant credited the Water Chemistry and One-Time Inspection programs to manage the SCC in the stainless steel pressurizer spray head exposed to reactor coolant. The staff also reviewed the applicants Water Chemistry and One-Time Inspection programs and its evaluations are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.11, respectively. The applicant indicated that the One-Time Inspection Program includes a one-time inspection of more susceptible materials in potentially more aggressive environments to manage the aging effect. The staff finds that the credited programs are adequate to manage the aging effect because: (a) the Water Chemistry Program monitors the plant water chemistry control parameters against the established parameter limits and, if a parameter exceeds the limit, the program performs adequate actions such that the water chemistry control continues to mitigate the aging effect; (b) the One-Time Inspection Program includes a one-time inspection of selected components to verify the effectiveness of the Water Chemistry Program consistent with the GALL Report; and (c) the one-time inspection can ensure that significant degradation does not occur and the components intended function is maintained during the period of extended operation. On the basis of its review, the staff finds that the applicants AMR results are consistent with those under GALL Report, Volume 2, item IV.C2-17 and the applicant satisfied the acceptance criteria in SRP-LR Section 3.1.2.2.16.2.
Based on the programs identified, the staff concludes that the applicants programs meet SRP-LR Section 3.1.2.2.16 criteria. For those 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 Stress-Corrosion Cracking, Primary Water Stress-Corrosion Cracking, and Irradiation-Assisted Stress-Corrosion Cracking The staff reviewed LRA Section 3.1.2.2.17 against the criteria in SRP-LR Section 3.1.2.2.17.
LRA Section 3.1.2.2.17 addresses cracking due to SCC, PWSCC, and IASCC in stainless steel and nickel-alloy PWR reactor internal components exposed to reactor coolant and neutron flux as an aging effect that the applicant will manage, consistent with the SRP-LR, with the Water Chemistry Program and the commitment of the PWR Vessel Internals Program.
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Aging Management Review Results SRP-LR Section 3.1.2.2.17 states that:
Cracking due to SCC, PWSCC, and IASCC could occur in PWR stainless steel and nickel alloy reactor vessel internals components. 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 AMR if the applicant provides a commitment in the [U]FSAR Supplement to (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval.
As indicated in SER Section 3.0.3.1.2, the staff accepts the Water Chemistry Program for mitigating the aging effects due to SCC, PWSCC, and IASCC, meeting one of the requirements mentioned in SRP-LR Section 3.1.2.2.17. Furthermore, the applicant made a commitment to incorporate all three GALL Report requirements stated above to manage this aging effect. The PWR Vessel Internals Program contains this commitment (Commitment No. 7). Commitment No. 7 is also identified in UFSAR Section A.2.1.7. Therefore, the staff concludes that the applicants program meets the SRP-LR Section 3.1.2.2.17 criteria. The staff also confirmed that LRA Table 3.1.2-3 identified all GALL Report Table IV.B2 items and the components under them for this aging effect (IV.B2-16, IV.B2-20, IV.B2-28, and IV.B2-40). For GALL Report item IV.B2-20, the applicant identified additional RPV internal components which are different but consistent with these GALL Report items for material, environment, and aging effect. For most of the GALL Report Table IV.B2 items mentioned above, LRA Table 3.1.2-3 provides a set of subcomponents to represent a single component in GALL Report Table IV.B2. The applicants approach of including additional components under the required AMP for GALL Report item IV.B2-20 is conservative and acceptable.
It was mentioned in SER Section 3.1.2.2.12 that LRA Table 3.1.2-3 does not distinguish the aging effects discussed in LRA Sections 3.1.1.1.12 and 3.1.2.2.17. This has no impact on the AMP managing the PWR internals under these two aging effects as explained in SER Section 3.1.2.2.12.
Based on a review of the programs identified, the staff concludes that the applicants programs meet SRP-LR Section 3.1.2.2.17 criteria. For those line items that apply to LRA Section 3.1.2.2.17, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended 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 staffs evaluation of the applicants QA program.
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APPENDIX A SALEM NUCLEAR GENERATING STATION LICENSE RENEWAL COMMITMENTS During the review of the Salem Nuclear Generating Station (Salem) license renewal application (LRA) by the staff of the U.S. Nuclear Regulatory Commission (NRC or the staff), PSEG Nuclear, LLC (PSEG or the applicant) made commitments related to aging management programs (AMPs) to manage aging effects for structures and components. The following table lists these commitments along with the implementation schedules and sources for each commitment.
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LRA Section 1 ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD A.2.1.1 Ongoing LRA Section B.2.1.1 2 Water Chemistry A.2.1.2 Ongoing LRA Section B.2.1.2 3 Reactor Head Closure Studs A.2.1.3 Ongoing LRA Section B.2.1.3 4 Boric Acid Corrosion A.2.1.4 Ongoing LRA Section B.2.1.4 5 Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure A.2.1.5 Ongoing LRA Section B.2.1.5 Heads of Pressurized Water Reactors 6 Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) is a A.2.1.6 Program to be LRA Section B.2.1.6 new program that will provide for aging management of the thermal implemented prior to embrittlement of CASS piping, piping elements and piping components in a the period of reactor coolant environment. The program will include a screening for extended operation.
components susceptible to thermal aging embrittlement based on casting method, molybdenum content, and percent ferrite. For potentially susceptible components, thermal aging embrittlement will be managed through either an enhanced volumetric inspection or a component-specific flaw tolerance evaluation.
7 PWR Vessel Internals is a new program that will include the following activities: A.2.1.7 Program to be LRA Section B.2.1.7 implemented prior to
- 1. Participate in the industry programs for investigating and managing the period of aging effects on reactor internals. extended operation.
- 2. Evaluate and implement the results of the industry programs as applicable to the reactor internals. Inspection plan to
- 3. Upon completion of these programs, but not less than 24 months be submitted to before entering the period of extended operation, submit an NRC not less than inspection plan for reactor internals to the NRC for review and 24 months prior to approval. the period of extended operation.
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LRA Section 8 Flow-Accelerated Corrosion A.2.1.8 Ongoing LRA Section B.2.1.8 9 Bolting Integrity Program is an existing program that will be enhanced to A.2.1.9 Program to be LRA Section B.2.1.9 include: enhanced prior to the period of
- 1. In the following cases, bolting material should not be reused: extended operation.
- a. Galvanized bolts and nuts,
- b. ASTM A490 bolts; and
- c. Any bolt and nut tightened by the turn of nut method.
10 Steam Generator Tube Integrity A.2.1.10 Ongoing LRA Section B.2.1.10 11 Open-Cycle Cooling Water System A.2.1.11 Ongoing LRA Section B.2.1.11 12 Closed-Cycle Cooling Water System is an existing program that will be A.2.1.12 Program to be LRA Section B.2.1.12 enhanced to include: enhanced and one-time inspections to
- 1. The Component Cooling System is not currently analyzed for sulfates, be implemented which is not consistent with the EPRI standard. The program will be prior to the period of enhanced to include monitoring this parameter as part of the Closed- extended operation.
Cycle Cooling Water program.
- 2. The emergency diesel generator jacket water system is not currently analyzed for azole or ammonia, chlorides, fluorides, and microbiologically-influenced corrosion in accordance with the current EPRI standard. The program will be enhanced to include these parameters as part of the Closed-Cycle Cooling Water program.
- 3. The Closed-Cycle Cooling Water program for the Chilled Water System will have a program or hardware change to bring the system chemistry parameters into compliance with EPRI 1007820, prior to the period of extended operation.
- 4. New recurring tasks will be established to enhance the performance monitoring of selected heat exchangers cooled by Component Cooling System.
- 5. New recurring tasks will be established for enhancing the A-3
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LRA Section performance monitoring of selected Chilled Water System components.
- 6. A one-time inspection of selected components will be established for Chilled Water System piping to confirm the effectiveness of the Closed-Cycle Cooling Water program.
- 7. A one-time inspection of selected closed-cycle cooling water components in stagnant flow areas will be conducted to confirm the effectiveness of the Closed-Cycle Cooling Water program.
- 8. A one-time inspection of selected closed-cycle cooling water chemical mixing tanks and associated piping will be conducted to confirm the effectiveness of the closed cycle cooling water program on the interior surfaces of the tanks and associated piping.
- 9. The program will be enhanced such that the Heating Water and Heating Steam System will have a pure water control program instituted, in accordance with EPRI 1007820, prior to the period of extended operation.
- 10. New recurring tasks will be established for enhancing the performance monitoring of selected Heating Water and Heating Steam System components.
- 11. A one-time inspection of selected Heating Water and Heating Steam System piping will be conducted to confirm the effectiveness of the Closed-Cycle Cooling Water program.
13 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) A.2.1.13 Program to be LRA Section B.2.1.13 Handling Systems is an existing program that will be enhanced to include: enhanced prior to the period of
- 1. Visual inspection of structural components and structural bolts for loss extended operation.
of material due to general, pitting, and crevice corrosion and structural bolting for loss of preload due to self-loosening.
- 2. Visual inspection of the rails in the rail system for loss of material due to wear.
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LRA Section
- 3. The acceptance criteria will be enhanced to require evaluation of significant loss of material due to corrosion for structural components and structural bolts, and significant loss of material due to wear of rail in the rail system.
14 Compressed Air Monitoring A.2.1.14 Ongoing LRA Section B.2.1.14 15 Fire Protection is an existing program that will be enhanced to include: A.2.1.15 Program to be LRA Section B.2.1.15 enhanced prior to
- 1. The routine inspection procedures will be enhanced to provide the period of Salem Letter additional inspection guidance to identify degradation of fire barrier extended operation. LR-N10-0225 walls, ceilings, and floors for aging effects such as cracking, spalling RAI B.2.1.15-02 and loss of material caused by freeze-thaw, chemical attack, and July 8, 2010 reaction with aggregates.
- 2. The fire pump supply line functional tests will be enhanced to provide specific guidance for examining exposed external surfaces of the fire pump diesel fuel oil supply line for corrosion during pump tests.
- 3. The Halon and Carbon Dioxide fire suppression system functional test procedures will be enhanced to include visual inspection of system piping and component external surfaces for signs of corrosion or other age related degradation, and for mechanical damage. The system functional test procedures will also be enhanced to include acceptance criteria stating that identified corrosion or mechanical damage will be evaluated with corrective action taken as appropriate.
16 Fire Water System is an existing program that will be enhanced to include: A.2.1.16 Program to be LRA Section B.2.1.16 enhanced prior to
- 1. The Fire Water System aging management program will be enhanced the period of to inspect selected portions of the water based fire protection system extended operation.
piping located aboveground and exposed to the fire water internal environment by non-intrusive volumetric examinations. These Inspection schedule inspections shall be performed prior to the period of extended identified in operation and will be performed every 10 years thereafter. Commitment.
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LRA Section
- 2. The Fire Water System aging management program will be enhanced to replace or perform 50-year sprinkler head inspections and testing using the guidance of NFPA-25 Standard for the Inspection, Testing and Maintenance of Water-Based Fire Protection Systems (2002 Edition), Section 5-3.1.1. These inspections will be performed by the 50-year in-service date and every 10-years thereafter.
17 Aboveground Steel Tanks is an existing program that will be enhanced to A.2.1.17 Program to be LRA Section B.2.1.17 include: enhanced prior to the period of
- 1. The program will be enhanced to include UT measurements of the extended operation.
bottom of the tanks that are supported on concrete foundations (Fire Tank bottom UT Protection Water Storage Tanks). Measured wall thickness will be inspections will also monitored and trended if significant material loss is detected. These be performed prior thickness measurements of the tank bottom will be taken and to the period of evaluated against design thickness and corrosion allowance to extended operation.
ensure that significant degradation is not occurring and the component intended function would be maintained during the extended period of operation.
- 2. The program will be enhanced to provide routine visual inspections of the Fire Protection Water Storage Tanks external surfaces. The visual inspection activities will include inspection of the grout or sealant between the tank bottom and the concrete foundation for signs of degradation.
18 Fuel Oil Chemistry is an existing program that will be enhanced to include: A.2.1.18 Program to be LRA Section B.2.1.18 enhanced and
- 1. Equivalent requirements for fuel oil purity and fuel oil testing as one-time described by the Standard Technical Specifications. inspections to be
- 2. Analysis for particulate contamination in new and stored fuel oil. implemented prior to
- 3. Addition of biocides, stabilizers and corrosion inhibitors as determined the period of by fuel oil sampling or inspection activities. extended operation.
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LRA Section
- 4. Quarterly analysis for bacteria in new and stored fuel oil.
- 5. Internal inspection of 350-gallon Fire Pump Day Tanks (S1DF-1DFE21 and S1DF-1DFE23) using visual inspections and ultrasonic thickness examination of tank bottoms.
- 6. Sampling of new fuel oil deliveries for API gravity and flash point prior to off load.
- 7. Internal inspection of the 30,000-gallon Fuel Oil Storage Tanks (S1DF-1DFE1, S1DF-1DFE2, S2DF-2DFE1 and S2DF-2DFE2) using visual inspections and ultrasonic thickness examination of tank bottoms.
- 8. To confirm the absence of any significant aging effects, a one-time inspection of each of the 550-gallon Diesel Fuel Oil Day Tanks will be performed.
19 Reactor Vessel Surveillance is an existing program that will be enhanced to A.2.1.19 Program to be LRA Section B.2.1.19 include: enhanced prior to the period of
- 1. The Reactor Vessel Surveillance program will be enhanced to state extended operation.
the bounding vessel inlet temperature (cold leg) limits and fluence projections, and to provide instructions for changes.
- a. Inlet Temperature Range Limitation: 525°F (min) to 590°F (max) 20 2
- b. Fluence Limitation (max.): 1.00 x 10 n/cm (E > 1.0 MeV)
- 2. The Reactor Vessel Surveillance program will be enhanced to describe the capsule storage requirements and the need to retain future pulled capsules.
- 3. The Reactor Vessel Surveillance program will be enhanced to specify a scheduled date for withdrawal of capsules including pulling one of the remaining four capsules during the period of extended operation to monitor the effects of long-term exposure to neutron embrittlement for each Salem Unit. Those dates shall be approved by the NRC prior to withdrawal of the capsules, in accordance with 10 CFR Part 50, A-7
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LRA Section Appendix H.
- 4. The Reactor Vessel Surveillance program will be enhanced to incorporate the requirements for (1) withdrawing the remaining capsules when the monitor capsule is withdrawn during the period of extended operation and placing them in storage for the purpose of reinstituting the Reactor Vessel Surveillance Program if required, i.e.
if the reactor vessel exposure conditions (neutron flux, spectrum, irradiation temperature, etc.) are altered, and subsequently the basis for the projection to 60 years warrant the reinstitution, and (2) changes to the reactor vessel exposure conditions and the potential need to re-institute a vessel surveillance program will be discussed with the NRC staff prior to changing the plant's licensing basis.
- 5. Enhancements to the current Reactor Vessel Surveillance program will be made to require that if future plant operations exceed the limitations or bounds specified for cold leg temperatures (vessel inlet) or higher fluence projections, then the impact of plant operation changes on the extent of reactor vessel embrittlement will be evaluated and the NRC shall be notified.
- a. Inlet Temperature Range Limitation: 525°F (min) to 590°F (max) 20 2
- b. Fluence Limitation (max.): 1.00 x 10 n/cm (E > 1.0 MeV) 20 One-Time Inspection is a new program and will be used for the following: A.2.1.20 Program to be LRA Section B.2.1.20 implemented prior to
- 1. To confirm the effectiveness of the Water Chemistry program to the period of Salem Letter manage the loss of material, cracking, and the reduction of heat extended operation. LR-N11-0005 transfer aging effects for aluminum, copper alloy, nickel alloy, steel, One-time RAI B.2.1.20-01 stainless steel, and cast austenitic stainless steel in treated water, inspections to be January 6, 2011 treated borated water where dissolved oxygen may not be controlled performed within the to less than 100 ppb, steam, and reactor coolant environments. ten-year period prior Salem Letter
- 2. To confirm the effectiveness of the Fuel Oil Chemistry program to to the period of extended operation. LR-N11-0148 manage the loss of material aging effect for aluminum, copper alloy, A-8
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LRA Section gray cast iron, steel and stainless steel in a fuel oil environment. May 18, 2011
- 3. To confirm the effectiveness of the Lubricating Oil Analysis program to manage the loss of material and the reduction of heat transfer aging effects for aluminum, copper alloy, ductile cast iron, gray cast iron, steel, stainless steel, cast austenitic stainless steel and titanium alloy in a lubricating oil environment.
The sample plan for inspections associated with the One-Time Inspection program will be developed to ensure there are adequate inspections to address each of the material, environment, and aging effect combinations. A sample size of 20% of the population (up to a maximum of 25 inspections) will be established for each of the sample groups.
21 Selective Leaching of Materials is a new program that will include one-time A.2.1.21 Program to be LRA Section B.2.1.21 inspections of a representative sample of susceptible components to implemented prior to determine where loss of material due to selective leaching is occurring. A the period of Salem Letter sample size of 20% of susceptible components will be subjected to a one-time extended operation. LR-N10-0324 inspection with a maximum of 25 inspections for each of the susceptible One-time September 1, 2010 material groups. Where selective leaching is identified, further aging inspections to be management activities will be implemented such that the component intended performed within the Salem Letter function is maintained consistent with the current licensing basis through the ten-year period prior LR-N11-0005 period of extended operation. to the period of RAI B.2.1.21-01 extended operation.
January 6, 2011 22 Buried Piping Inspection is an existing program that will be enhanced to A.2.1.22 Program to be LRA Section B.2.1.22 include: enhanced prior to the period of Salem Letter
- 1. A cathodic protection study will be performed prior to entering the extended operation. LR-N10-0322 period of extended operation to assess the possibility and benefits of RAI B.2.1.22 installing a system, versus other mitigative and preventive actions. Inspection Schedule September 7, 2010
- 2. A soil characterization study will be performed prior to entering the identified in period of extended operation to determine soil corrosivity in the Commitment. Salem Letter A-9
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LRA Section vicinity of buried piping. The results of the study will be used as an LR-N10-0372 input to the program so that inspections will be performed at the RAI B.2.1.22-02 locations of highest risk. November 10, 2010
- 3. At least one (1) opportunistic or focused excavation and inspection will be performed on each of the Fire Protection System material Salem Letter groupings, which include carbon steel, ductile cast iron, and gray cast LR-N10-0444 iron piping and components during each ten (10) year period, RAI B.2.1.22-03 beginning ten (10) years prior to entry into the period of extended January 18, 2011 operation.
- 4. The following inspections apply to buried, carbon steel, safety-related portions of the specified systems. A different segment for each system will be inspected in each ten year period.
- a. At least one (1) opportunistic or focused excavation and inspection on each of the Auxiliary Feedwater and Compressed Air systems during the ten (10) years prior to entering the period of extended operation.
- b. At least three (3) opportunistic or focused excavations and inspections of the Service Water System during the ten (10) years prior to entering the period of extended operation.
- c. If, as a result of the soil characterization study, it is determined that the soil is not corrosive in the vicinity of all of the Auxiliary Feedwater, Service Water, and Compressed Air systems, Salem will perform at least (1) opportunistic or focused excavation and inspection on each of the respective systems every ten (10) years during the period of extended operation.
- d. If, as a result of the soil characterization study, it is determined that the soil is corrosive in the vicinity of the Auxiliary Feedwater, Service Water, or Compressed Air systems, Salem will perform at least two (2) opportunistic or focused excavations and inspections on the respective A-10
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LRA Section susceptible system(s) every ten (10) years during the period of extended operation.
- 5. If, based on the results of the initial soil characterization study, it is determined that the soil is not corrosive in the vicinity of the Auxiliary Feedwater, Service Water, or Compressed Air systems, Salem will perform a second Soil Characterization Study within approximately fifteen (15) years of the original study. The results of the second soil study will be entered into the Corrective Action Program for evaluation.
- 6. The buried Auxiliary Feedwater System piping located inside the Unit 2 Fuel Transfer Tube Area (approximately 125 feet) will be replaced and rerouted above ground prior to entering the period of extended operation.
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LRA Section 23 One-Time Inspection of ASME Code Class 1 Small-Bore Piping is a new A.2.1.23 Program to be LRA Section B.2.1.23 program that will manage the aging effect of cracking in stainless steel implemented prior to small-bore, less than nominal pipe size (NPS) 4 inches and greater than or the period of Salem Letter equal to NPS 1 Class 1 piping through the use of a combination of volumetric extended operation. LR-N10-0247 examinations and visual inspections. One-time RAI B.2.1.23-01 inspections to be July 8, 2010 The One-Time Inspection of ASME Code Class 1 Small Bore-Piping is a new performed within the program that will be enhanced to include the following activity: ten-year period prior to the period of Salem Units 1 and 2 will perform four volumetric examinations, two per unit, extended operation.
from a population of 36 susceptible Class 1 small-bore socket welds on Unit 1 and 34 susceptible Class 1 small-bore socket welds on Unit 2. Provided the Program to be technology is available, these inspections shall be performed prior to entering enhanced prior to the period of extended operation. More specifically, the volumetric the period of examinations will analyze Class 1 small-bore socket welds as follows: extended operation.
x Two Class 1 small-bore socket welds (one per unit) for intergranular stress corrosion cracking; and The inspection x Two Class 1 small-bore socket welds (one per unit) for cracking schedule will be caused by thermal fatigue (thermal and mechanical loading) consistent with the Salem ISI Program requirements.
24 External Surfaces Monitoring is a new program that directs visual inspections A.2.1.24 Program to be LRA Section B.2.1.24 of components such as piping, piping components, ducting and other implemented prior to components in the scope of license renewal, exposed to an air environment, to the period of manage aging effects. extended operation.
25 Flux Thimble Tube Inspection is a new program that manages the loss of A.2.1.25 Program to be LRA Section B.2.1.25 material due to wear of the flux thimble tube materials using inspection implemented prior to methods such as eddy current testing. the period of extended operation.
26 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting A.2.1.26 Program to be LRA Section B.2.1.26 A-12
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LRA Section Components is a new program that manages the aging of the internal surfaces implemented prior to of piping, piping components, piping elements, ducting components, tanks and the period of heat exchanger components. extended operation.
27 Lubricating Oil Analysis A.2.1.27 Ongoing LRA Section B.2.1.27 28 ASME Section XI, Subsection IWE is an existing program that will be A.2.1.28 Program to be LRA Section B.2.1.28 enhanced to include: enhanced prior to the period of Salem Letter
- 1. Inspection of a sample of the inaccessible liner covered by insulation extended operation. LR-N10-0165 and lagging once prior to the period of extended operation and every RAI B.2.1.28-1 10 years thereafter. Should unacceptable degradation be found Inspection Schedule RAI B.2.1.28-2 additional insulation will be removed as necessary to determine identified in May 13, 2010 extent of condition in accordance with the corrective action process. Commitment.
Salem Letter Prior to the period of extended operation LR-N10-0244 RAI 3.5.2.2.1.7-01 x The samples shall include 57 randomly selected containment July 15, 2010 liner insulation panels per unit.
x The randomly selected containment liner insulation panels will Salem Letter not include containment liner insulation panels previously LR-N10-0321 removed to allow for inspection. RAI B.2.1.28-04 x The examination will be performed by either removing the RAI B.2.1.33-06 containment liner insulation panels and performing a visual September 1, 2010 inspection, or by using a pulsed eddy current (PEC) remote inspection, with the containment liner insulation left in place, to Salem Letter detect evidence of loss of material. If evidence of loss of material LR-N10-0382 is detected using PEC, the containment liner insulation panel will October 15, 2010 be subsequently removed to allow for visual and UT examinations.
x All inspections will be completed by August 2016 for both Salem Units. Approximately one third of the 57 inspections will be A-13
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LRA Section completed during each refuel outage (Salem Unit 1 involves the following refuel outages: Spring 2013, Fall 2014, and Spring 2016. Salem Unit 2 involves the following refuel outages: Fall 2012, Spring 2014, and Fall 2015). It is acceptable to perform greater than one third of the inspections in any refuel outage to accelerate the inspection schedule.
During the period of extended operation x One containment liner insulation panel will be selected, at random, for removal from each quadrant, during each of the three Periods in an Inspection Interval. Therefore, a total of 12 containment liner insulation panels will be selected, in each unit, during each ten year Inspection Interval, to allow for examination of the containment liner behind the containment liner insulation.
x The randomly selected containment liner insulation panels in each quadrant will not include containment liner insulation panels previously selected.
- 2. Visual inspection of 100% of the moisture barrier, at the junction between the containment concrete floor and the containment liner, will be performed in accordance with ASME Section XI, Subsection IWE program requirements, to the extent practical within the limitation of design, geometry, and materials of construction of the components.
The bottom edge of the stainless steel insulation lagging will be trimmed, if necessary, to perform the moisture barrier inspections.
This inspection will be performed prior to the period of extended operation, and on a frequency consistent with IWE inspection requirements thereafter. Should unacceptable degradation be found, corrective actions, including extent of condition, will be addressed in accordance with the corrective action process.
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LRA Section As a follow-up to inspections performed during the 2009 refueling outage, the following specific corrective actions will be performed on Unit 2 prior to entry into the period of extended operation:
x Examine the accessible 3/4 knuckle plate. If corrosion is observed to extend below the surface of the moisture barrier, excavate the moisture barrier to sound metal below the floor level and perform examinations as required by IWE.
x Perform remote visual inspections, of the six capped vertical leak chase channels, below the containment floor to determine extent of condition.
x Remove the concrete floor and expose the 1/4 containment liner plate (floor) for a minimum of two of the vertical leak chase channels with holes. Perform examination of exposed 1/4 containment liner plate (floor) as required by IWE. Additional excavations will be performed, if necessary, depending upon conditions found at the first two channels.
x Remove 1/2 containment liner insulation panels, adjacent to accessible areas where there are indications of corrosion, to determine the extent of condition of the existing corroded areas of the containment liner plate.
x Perform augmented examinations of the areas of the 1/2 containment liner plate behind insulation panels, where loss of material was previously identified, in accordance with IWE-2420.
x Examine 100% of the moisture barrier in accordance with IWE-2310 and replace or repair the moisture barrier to meet the acceptance standard in IWE-3510.
As a follow-up to inspections performed during the 2010 refueling A-15
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LRA Section outage, the following specific corrective actions will be performed on Unit 1 prior to entry into the period of extended operation:
x Perform augmented examinations of the 3/4 containment liner (knuckle plate) at 78 elevation in accordance with IWE-2420.
x Perform augmented examinations of the areas of the 1/2 containment liner plate behind insulation panels, where loss of material was previously identified, in accordance with IWE-2420.
x Remove 1/2 containment liner insulation panels, adjacent to accessible areas where there are indications of corrosion, to determine the extent of condition of the existing corroded areas of the containment liner plate.
- 3. ASME Section XI, Subsection IWE program scope will be revised to include the following welds that are currently exempted from Subsection IWE and governed under ASME Section XI, Subsection IWB or IWC. The scope of the revision will include the cap plate to penetrating pipe pressure boundary welds, for penetrating pipe constructed of stainless steel for those penetrations with a normal operating temperature greater than 140 degrees F.
- 4. Owner augmented inspections will be performed at the Salem Unit 1 and Unit 2 area of the Containment liner, under the fuel transfer canal and behind the Containment liner insulation, which are subjected to leaks from the reactor cavity. These owner augmented inspections will be performed on a frequency of once per Containment Inservice Inspection Period, starting with the current Period. These owner augmented inspections will continue, under the IWE program, as long as leakage from the reactor cavity or fuel transfer canal is observed between the Containment liner and the Containment liner insulation, including during the PEO.
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LRA Section 29 ASME Section XI, Subsection IWL, is an existing program that will be A.2.1.29 Program to be LRA Section B.2.1.29 enhanced to include: enhanced prior to the period of Salem Letter
- 1. Examination and acceptance criteria in accordance with the guidance extended operation. LR-N10-0165 contained in ACI 349.3R. RAI B.2.1.29-1 May 13, 2010 30 ASME Section XI, Subsection IWF A.2.1.30 Ongoing LRA Section B.2.1.30 31 10 CFR Part 50, Appendix J A.2.1.31 Ongoing LRA Section B.2.1.31 32 Masonry Wall is an existing program that will be enhanced to include: A.2.1.32 Program to be LRA Section B.2.1.32 enhanced prior to
- 1. Additional buildings and masonry walls as described in A.2.1.32. the period of
- 2. Add an Examination Checklist for masonry wall inspection extended operation.
requirements.
- 3. Specify an inspection frequency of not greater than 5 years for masonry walls.
33 Structures Monitoring is an existing program that will be enhanced to include: A.2.1.33 Program to be LRA Section B.2.1.33 enhanced prior to
- 1. Additional structures and components as described in A.2.1.33. the period of Salem Letter
- 2. Concrete structures will be observed for a reduction in equipment extended operation. LR-N10-0165 anchor capacity due to local concrete degradation. This will be RAI B.2.1.33-1 accomplished by visual inspection of concrete surfaces around Core sample RAI B.2.1.33-2 anchors for cracking and spalling. Inspection schedule May 13, 2010
- 3. Clarify that inspections are performed for loss of material due to identified in corrosion and pitting of additional steel components, such as commitment. Salem Letter embedments, panels and enclosures, doors, siding, metal deck, and LR-N10-0321 anchors. RAI B.2.1.33-05
- 4. Require inspection of penetration seals, structural seals, and September 1, 2010 elastomers, for degradations that will lead to a loss of sealing by visual inspection of the seal for hardening, shrinkage and loss of Salem Letter A-17
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LRA Section strength. LRN-N10-0414
- 5. Require the following actions related to the spent fuel pool liner: RAI B.2.1.33-07
- a. Perform periodic structural examination of the Fuel Handling December 14, 2010 Building per ACI 349.3R to ensure structural condition is in agreement with the analysis. Salem letter
- b. Monitor telltale leakage and inspect the leak chase system to LR-N11-0041 ensure no blockage. RAI B.2.1.33-07
- c. Test water drained from the telltales and seismic gap for boron, Update chloride, iron, and sulfate concentrations; and pH. Acceptance February 25, 2011 criteria will assess any degradation from the borated water.
Sample readings outside the acceptance criteria will be entered into and evaluated in the corrective action program.
- d. Perform one shallow core sample in each of the Unit 1 Spent Fuel Pool walls (east and west) that have shown ingress of borated water through the concrete. The core samples will be examined for degradation from borated water. Also the core samples (east and west walls) will expose rebar, which will be examined for signs of corrosion. The core sample from the west wall will be taken by the end of 2013 and the core sample from the east wall will be taken by the end of 2015.
- e. Perform a structural examination per ACI 349.3R every 18 months of the Unit 1 Spent Fuel Pool wall in the sump room where previous inspections have shown ingress of borated water through the concrete.
- 6. Require monitoring of vibration isolators, associated with component supports other than those covered by ASME XI, Subsection IWF.
- 7. Add an Examination Checklist for masonry wall inspection requirements.
- 8. Parameters monitored for wooden components will be enhanced to include: Change in Material Properties, Loss of Material due to Insect Damage and Moisture Damage.
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LRA Section
- 9. Specify an inspection frequency of not greater than 5 years for structures including submerged portions of the service water intake structure.
- 10. Require individuals responsible for inspections and assessments for structures to have a B.S. Engineering degree and/or Professional Engineer license, and a minimum of four years experience working on building structures.
- 11. Perform periodic sampling, testing, and analysis of ground water chemistry for pH, chlorides, and sulfates on a frequency of 5 years.
Groundwater samples in the areas adjacent to Unit 1 containment structure and Unit 1 auxiliary building will also be tested for boron concentration.
- 12. Require supplemental inspections of the affected in scope structures within 30 days following extreme environmental or natural phenomena (large floods, significant earthquakes, hurricanes, and tornadoes).
- 13. Perform a chemical analysis of ground or surface water in-leakage when there is significant in-leakage or there is reason to believe that the in-leakage may be damaging concrete elements or reinforcing steel.
- 14. Implementing procedures will be enhanced to include additional acceptance criteria details specified in ACI 349.3R-96.
- 15. When the reactor cavity is flooded up, Salem will periodically monitor the telltales associated with the reactor cavity and refueling canal for leakage. If telltale leakage is observed, then the pH of the leakage will be measured to ensure that concrete reinforcement steel is not experiencing a corrosive environment. In addition, Salem will periodically inspect the leak chase system associated with the reactor cavity and refueling canal to ensure the telltales are free of significant blockage. Salem will also inspect concrete surfaces for degradation where leakage has been observed, in accordance with this Program.
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LRA Section 34 RG 1.127, Inspection of Water-Control Structures Associated With Nuclear A.2.1.34 Program to be LRA Section B.2.1.34 Power Plants is an existing program that will be enhanced to include: enhanced prior to the period of
- 1. Parameters monitored for wooden components will be enhanced to extended operation.
include change in material properties and loss of material due to insect damage and moisture damage.
- 2. Parameters monitored for elastomers will be enhanced to include hardening, shrinkage and loss of strength due to weathering and elastomer degradation.
- 3. The inspection requirement for submerged concrete structural components will be enhanced to require that inspections be performed by dewatering a pump bay or by a diver if the pump bay is not dewatered.
- 4. Specify an inspection frequency of not greater than 5 years for structures including submerged portions of the Service Water Intake Structure.
- 5. Require supplemental inspections of the in scope structures within 30 days following extreme environmental or natural phenomena (large floods, significant earthquakes, hurricanes, and tornadoes).
35 Protective Coating Monitoring and Maintenance Program A.2.1.35 Ongoing LRA Section B.2.1.35 A-20
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LRA Section 36 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental A.2.1.36 Program and initial LRA Section B.2.1.36 Qualification Requirements is a new program and will be used to manage inspections to be aging of non-EQ cables and connections during the period of extended implemented prior to operation. the period of extended operation.
37 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental A.2.1.37 Program and initial LRA Section B.2.1.37 Qualification Requirements Used in Instrumentation Circuits is a new program assessment of that will be implemented to manage the aging of the cable and connection testing and insulation of the in scope portions of the Radiation Monitoring System and the calibration results to Reactor Protection System (i.e., the nuclear instrumentation system). be implemented prior to the period of extended operation.
38 Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 A.2.1.38 Enhanced program, LRA Section B.2.1.38 Environmental Qualification Requirements is a new program that will be used initial cable tests, to manage the aging effects and mechanisms of non-EQ, in scope and initial manhole Salem Letter inaccessible medium voltage cables (4,160V, 13,800V). and cable vault LR-N10-0225 inspections to be RAI B.2.1.38-01 The cable test frequency will be established based on test results and industry implemented prior to July 8, 2010 operating experience. The maximum time between tests will be no longer than the period of 6 years. extended operation.
Salem Letter LR-N10-0348 Manholes and cable vaults associated with the cables included in this aging Test and inspection LRA Supplement management program will be inspected for water collection (with water schedule identified October 7, 2010 removal as necessary) with the objective of minimizing the exposure of in commitment.
medium voltage cables to significant moisture. Prior to the period of extended operation, the frequency of inspections for accumulated water will be established based on inspection results to minimize the exposure of medium voltage cables to significant moisture. The maximum time between inspections will be no longer than one year.
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LRA Section The Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements aging management program will be enhanced as follows:
- 1. Change cable testing maximum frequency from 10 years to 6 years.
Change manhole and cable vault inspection maximum frequency from 2 years to 1 year.
39 Metal Enclosed Bus is a new program that will manage the aging of in-scope A.2.1.39 Program and initial LRA Section B.2.1.39 metal enclosed busses. inspections to be implemented prior to the period of extended operation.
40 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental A.2.1.40 Program and LRA Section B.2.1.40 Qualification Requirements is a new program that will be used to confirm the one-time testing to slow progression or the absence of an aging effect with respect to electrical be implemented cable connection stressors. A representative sample of non-EQ electrical cable prior to the period of connections will be selected, for one-time testing considering application extended operation.
(medium and low voltage), circuit loading (high loading) and location, with respect to connection stressors.
41 High Voltage Insulators is a new program that manages the degradation of A.2.2.1 Program to be LRA Section B.2.2.1 insulator quality due to the presence of salt deposits or surface contamination. implemented prior to the period of extended operation.
42 Periodic Inspection is a new program that manages the aging of piping, piping A.2.2.2 Program to be LRA Section B.2.2.2 components, piping elements, ducting components, tanks and heat exchanger implemented prior to components. the period of extended operation.
43 Aboveground Non-Steel Tanks is a new program that will manage loss of A.2.2.3 Program to be LRA Section B.2.2.3 material of outdoor non-steel tanks. The Aboveground Non-Steel Tanks implemented prior to program will include a UT wall thickness inspection of the bottom of the tanks. the period of A-22
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LRA Section The UT measurements will be taken to ensure that significant degradation is extended operation.
not occurring and that the component intended function will be maintained Tank bottom UT during the extended period of operation. inspections will also be performed prior to the period of extended operation.
44 Buried Non-Steel Piping Inspection is an existing program that will be A.2.2.4 Program to be LRA Section B.2.2.4 enhanced to include: enhanced prior to the period of Salem Letter
- 1. At least one (1) opportunistic or focused excavation and inspection extended operation. LR-N10-0322 will be performed on buried reinforced concrete piping and RAI B.2.1.22 components during each ten (10) year period, beginning ten (10) Inspection Schedule September 7, 2010 years prior to entry into the period of extended operation. identified in
- 2. At least one (1) opportunistic or focused excavation and inspection Commitment will be performed on buried stainless steel penetration bellows between the Containment Structure and the Fuel Handling Building, including the penetration sleeves, during each ten (10) year period, beginning ten (10) years prior to entry into the period of extended operation.
- 3. Guidance for inspection of concrete aging effects.
45 Boral Monitoring is an existing program that will be enhanced to include: A.2.2.5 Program to be LRA Section B.2.2.5 enhanced prior to
- 1. The program will be enhanced to perform a neutron attenuation the period of measurement on one each of the three (no vent holes, one vent holes extended operation.
and two vent holes) flat plate sandwich Boral test coupons during the first three two-year inspection frequency periods and every six years Inspection Schedule thereafter for the Exxon spent fuel storage rack assemblies. identified in
- 2. The program will be enhanced to include acceptance criteria of the Commitment.
neutron attenuation measurement on the Boral test coupons for the Exxon spent fuel storage rack assemblies: A decrease of no more A-23
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LRA Section than 5% in Boron-10 content as determined by neutron attenuation measurements. The benchmark Boron-10 content used for comparison will be based on the nominal B-10 areal density in the design basis specification.
46 Nickel Alloy Aging Management A.2.2.6 Ongoing LRA Section B.2.2.6 47 Metal Fatigue of the Reactor Coolant Pressure Boundary is an existing A.3.1.1 Program to be LRA Section B.3.1.1 program that will be enhanced to include: enhanced prior to the period of
- 1. Adding transients beyond those defined in the Technical extended operation.
Specifications and the UFSAR, and expanding the fatigue monitoring program to encompass other components identified to have fatigue as an analyzed aging effect, which require monitoring.
- 2. Using a software program to automatically count transients and calculate cumulative usage on select components.
- 3. Addressing the effects of the reactor coolant environment on component fatigue life by assessing the impact of the reactor coolant environment on a sample of critical components for the plant identified in NUREG/CR-6260.
- 4. Requiring 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.
48 Environmental Qualification of Electric Components (EQ) A.3.1.2 Ongoing LRA Section B.3.1.2 49 Revised Pressure-Temperature (P-T) limits will be submitted to the NRC when A.4.2.4 Ongoing LRA Section 4.2.4 necessary to comply with 10 CFR 50 Appendix G.
50 Steam Generator Divider Plate Inspection Not Applicable Prior to August 2026 Salem Letter LR-N10-0369 Salem will perform an inspection of each of the four (4) Unit 1 steam RAI 3.1.1-02 generators to assess the condition of the divider plate assembly. The October 7, 2010 examination technique(s) used will be capable of detecting primary water stress corrosion cracking (PWSCC) in the steam generator divider plate A-24
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LRA Section assemblies and the associated welds. The steam generator divider plate inspections will be completed within the first ten (10) years of the Salem Unit 1 period of extended operation.
51 Steam Generator Tube-to-Tubesheet Weld Cracking Not Applicable Develop a plan prior Salem Letter to the Period of LR-N10-0421 Salem will develop a plan for each Unit to address the potential for cracking of Extended Operation RAI 3.1.1-03 the primary to secondary pressure boundary due to PWSCC of tube-to- for each Unit. December 1, 2010 tubesheet welds. Each plan will consist of two options:
If the analysis option Salem Letter Salem Unit 1 is chosen, LR-N10-0438 implement the Revised Response to Option 1 (Analysis): requirements of the RAI 3.1.1-03 plan, including December 15, 2010 obtaining any Salem Unit 1 will obtain permanent approval for Alternate Repair Criteria from required NRC the NRC, or approval, by April 2018 for Unit 1, and Option 2 (inspection): by April 2028 for Unit 2.
Salem Unit 1 will perform a One-Time inspection of a representative number of tube-to-tubesheet welds in each of the four (4) steam generators to determine If steam generator if PWSCC is present. If weld cracking is identified, a) the condition will be inspections are to resolved through repair or engineering evaluation to justify continued service, be performed, they as appropriate, and b) a periodic monitoring program will be established to will be performed perform routine tube-to-tubesheet inspections for the remaining life of the between April 2018 steam generators. and April 2023 for Unit 1, and April Salem Unit 2 2028 and April 2033 for Unit 2.
Option 1 (Analysis):
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LRA Section Salem Unit 2 will perform an analytical evaluation either determining that the tubesheet cladding and welds are not susceptible to PWSCC, or redefining the pressure boundary of the tubes, where the steam generator tube-to-tubesheet welds are not required for the reactor coolant pressure boundary function. The redefinition of the reactor coolant pressure boundary will be submitted as part of a license amendment request requiring approval from the NRC, or Option 2 (inspection):
Salem Unit 2 will perform a One-Time inspection of a representative number of tube-to-tubesheet welds in each of the four (4) steam generators to determine if PWSCC is present. If weld cracking is identified, a) the condition will be resolved through repair or engineering evaluation to justify continued service, as appropriate, and b) a periodic monitoring program will be established to perform routine tube-to-tubesheet inspections for the remaining life of the steam generators.
52 Salem will perform a review of design basis ASME Code Class 1 fatigue Not Applicable Prior to the period of Salem Letter evaluations to determine whether the NUREG/CR-6260 based locations that extended operation. LR-N10-0445 have been evaluated for the effects of the reactor coolant environment on RAI 4.3-08 fatigue usage are the limiting locations for the Salem plant configuration. If December 21, 2010 more limiting locations are identified, the most limiting location will be evaluated for the effects of the reactor coolant environment on fatigue usage.
If any of the limiting locations consist of nickel alloy, NUREG/CR-6909 methodology for nickel alloy will be used in the evaluation TM 53 Salem Fatigue Calculations using WESTEMS program A.4.3.7 Within 60 days of Salem Letter issuance of the LR-N11-0042 Salem will include written explanation and justification of any user intervention renewed January 31, 2011 in future evaluations using the WESTEMS Design CUF (NB-3200 module). operating license Salem Letter LR-N11-0057 A-26
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LRA Section February 24, 2011 TM 54 Salem Fatigue Calculations using WESTEMS program A.4.3.7 Within 60 days of Salem Letter issuance of the LR-N11-0042 Salem will not use or implement the NB-3600 option (module) of the renewed January 31, 2011 WESTEMS' program in future online fatigue monitoring and design operating license calculations. Salem Letter LR-N11-0057 February 24, 2011 A-27