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| | issue date = 01/02/2019 | | | issue date = 01/02/2019 |
| | title = Safety Evaluation Report Re License Renewal of Seabrook Station Unit 1. Supersedes ML18254A294 | | | title = Safety Evaluation Report Re License Renewal of Seabrook Station Unit 1. Supersedes ML18254A294 |
| | author name = Burton W F | | | author name = Burton W |
| | author affiliation = NRC/NRR/DMLR/MRPB | | | author affiliation = NRC/NRR/DMLR/MRPB |
| | addressee name = | | | addressee name = |
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| | docket = 05000443 | | | docket = 05000443 |
| | license number = | | | license number = |
| | contact person = Burton W F, (301) 415-6332 | | | contact person = Burton W, (301) 415-6332 |
| | document type = Safety Evaluation Report | | | document type = Safety Evaluation Report |
| | page count = 939 | | | page count = 939 |
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| =Text= | | =Text= |
| {{#Wiki_filter:Safety Evaluation Report Related to the License Renewal of Seabrook Station Docket No. 50 | | {{#Wiki_filter:}} |
| -443 NextEra Energy Seabrook, LLC United States Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Date Published:
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| | |
| ABSTRACT This safety evaluation report (SER) documents the technical review of the Seabrook Station, Unit No. 1 (Seabrook) license renewal application (LRA) by the U.S. Nuclear Regulatory Commission (NRC) staff (the staff). By letter dated May 25, 2010, NextEra Energy Seabrook, LLC (NextEra or the applicant), submitted the LRA in accordance with Title 10, of the Code of Federal Regulations, (10 CFR) Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants." NextEra requests renewal of the operating license (Facility Operating License Number NPF
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| -86) for a period of 20 years beyond the current expiration at midnight on March 15, 2030.
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| Seabrook is located in Seabrook Township, Rockingham County, New Hampshire, on the western shore of Hampton Harbor, 2 miles west of the Atlantic Ocean. The station is approximately 2 miles north of the Massachusetts State line and approximately 15 miles south of the Maine State line. A zero
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| -power license was granted for the facility in October 1986, and a full-power operating license was subsequently granted on March 15, 1990. Seabrook previously sought and received a modification to the expiration of the facility operating license to recapture the time licensed at zero
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| -percent power. The unit is a 4
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| -loop pressurized
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| -water reactor (PWR) design. Westinghouse supplied the nuclear steam supply system. United Engineers and Construction constructed the balance of plant. The licensed power output of the unit is 3,648 megawatts thermal.
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| Unless otherwise indicated, this SER presents the status of the staff's review of information submitted through July 2018. In the 2012 SER with Open Items, the staff identified seven open items that must be resolved before any final determination can be made on the LRA. SER Section 1.5 summarizes the resolution of the open items. The staff presents its conclusion on the LRA review in this SER.
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| TABLE OF CONTENTS ABSTRACT .............................................................................................................................. iii LIST OF TABLES .................................................................................................................. xvii ABBREVIATIONS .................................................................................................................. xix SECTION 1 INTRODUCTION AND GENERAL DISCUSSION ............................................ 1
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| -1 1.1 Introduction ............................................................................................................... 1
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| -1 1.2 License Renewal Background .................................................................................. 1
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| -2 1.2.1 Safety Review ............................................................................................... 1
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| -3 1.2.2 Environmental Review .................................................................................. 1
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| -4 1.3 Principal Review Matters .......................................................................................... 1
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| -5 1.4 Interim Staff Guidance .............................................................................................. 1
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| -6 1.5 Summary of Closure of Open Items .......................................................................... 1
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| -8 1.6 Summary of Confirmatory Items ............................................................................. 1
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| -11 1.7 Summary of Proposed License Conditions ............................................................. 1
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| -11 SECTION 2 STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW ................................................................................ 2
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| -1 iii 2.1 Scoping and Screening Methodology ....................................................................... 2
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| -1 2.1.1 Introduction ................................................................................................... 2
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| -1 2.1.2 Summary of Technical Information in the Application .................................... 2
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| -1 2.1.3 Scoping and Screening Program Review ...................................................... 2
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| -2 2.1.3.1 Implementation Procedures and Documentation Sources for Scoping and Screening ................................................................. 2
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| -3 2.1.3.2 Quality Controls Applied to LRA Development .............................. 2
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| -5 2.1.3.3 Training ......................................................................................... 2
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| -6 2.1.3.4 Scoping and Screening Program Review Conclusion .................... 2
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| -7 2.1.4 Plant Systems, Structures, and Components Scoping Methodology ............. 2
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| -7 2.1.4.1 Application of the Scoping Criteria in 10 CFR 54.4(a)(1)
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| ............... 2
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| -7 2.1.4.2 Application of the Scoping Criteria in 10 CFR 54.4(a)(2) ............. 2
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| -10 2.1.4.3 Application of the Scoping Criteria in 10 CFR 54.4(a)(3) ............. 2
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| -22 2.1.4.4 Plant-Level Scoping of Systems and Structures .......................... 2
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| -26 2.1.4.5 Mechanical Scoping .................................................................... 2
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| -29 2.1.4.6 Structural Scoping ....................................................................... 2
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| -30 2.1.4.7 Electrical Component Scoping .................................................... 2
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| -31 2.1.4.8 Scoping Methodology Conclusion ............................................... 2
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| -32 2.1.5 Screening Methodology .............................................................................. 2
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| -32 2.1.5.1 General Screening Methodology ................................................. 2
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| -32 2.1.5.2 Mechanical Component Screening .............................................. 2
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| -34 2.1.5.3 Structural Component Screening ................................................ 2
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| -35 2.1.5.4 Electrical Component Screening ................................................. 2
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| -36 Table of Contents iv 2.1.5.5 Screening Methodology Conclusion ............................................ 2
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| -38 2.1.6 Summary of Evaluation Findings ................................................................. 2
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| -38 2.2 Plant-Level Scoping Results ................................................................................... 2
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| -38 2.2.1 Introduction ................................................................................................. 2
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| -38 2.2.2 Summary of Technical Information in the Application .................................. 2
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| -39 2.2.3 Staff Evaluation ........................................................................................... 2
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| -39 2.2.4 Conclusion .................................................................................................. 2
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| -40 2.3 Scoping and Screening Results: Mechanical Systems ........................................... 2
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| -40 2.3.1 Reactor Vessel, Internals, and Reactor Coolant System ............................. 2
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| -41 2.3.1.1 Reactor Coolant System ............................................................. 2
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| -41 2.3.1.2 Reactor Vessel ............................................................................ 2
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| -42 2.3.1.3 Reactor Vessel Internals ............................................................. 2
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| -43 2.3.1.4 Steam Generators ....................................................................... 2
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| -44 2.3.2 Engineered Safety Features ........................................................................ 2
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| -44 2.3.2.1 Combustible Gas Control System ............................................... 2
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| -45 2.3.2.2 Containment Building Spray System ........................................... 2
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| -45 2.3.2.3 Residual Heat Removal System .................................................. 2
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| -46 2.3.2.4 Safety Injection System ............................................................... 2
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| -47 2.3.3 Auxiliary Systems ........................................................................................ 2
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| -48 2.3.3.1 Auxiliary Boiler ............................................................................ 2
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| -49 2.3.3.2 Boron Recovery System .............................................................. 2
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| -50 2.3.3.3 Chemical and Volume Control System ........................................ 2
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| -52 2.3.3.4 Chlorination System .................................................................... 2
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| -53 2.3.3.5 Containment Air Handling System ............................................... 2
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| -54 2.3.3.6 Containment Air Purge System ................................................... 2
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| -54 2.3.3.7 Containment Enclosure Air Handling System .............................. 2
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| -55 2.3.3.8 Containment Online Purge System ............................................. 2
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| -56 2.3.3.9 Control Building Air Handling System .......................................... 2
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| -57 2.3.3.10 Demineralized Water System ...................................................... 2
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| -57 2.3.3.11 Dewatering System ..................................................................... 2
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| -58 2.3.3.1 2 Diesel Generator ......................................................................... 2
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| -59 2.3.3.13 Diesel Generator Air Handling System ........................................ 2
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| -60 Table of Contents v 2.3.3.14 Emergency Feedwater Pump House Air Handling System .......... 2
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| -61 2.3.3.15 Fire Protection System ................................................................ 2
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| -61 2.3.3.16 Fuel Handling System ................................................................. 2
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| -71 2.3.3.17 Fuel Oil System ........................................................................... 2
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| -71 2.3.3.18 Fuel Storage Building Air Handling System ................................. 2
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| -72 2.3.3.19 Hot Water Heating System ..........................................................
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| 2-73 2.3.3.20 Instrument Air System ................................................................. 2
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| -75 2.3.3.21 Leak Detection System ............................................................... 2
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| -78 2.3.3.22 Mechanical Seal Supply System ................................................. 2
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| -78 2.3.3.23 Miscellaneous Equipment ........................................................... 2
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| -79 2.3.3.24 Nitrogen Gas System .................................................................. 2
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| -79 2.3.3.25 Oil Collection for Reactor Coolant Pumps System ....................... 2
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| -80 2.3.3.26 Plant Floor Drain System ............................................................ 2
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| -80 2.3.3.27 Potable Water System................................................................. 2
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| -82 2.3.3.28 Primary Auxiliary Building Air Handling System ........................... 2
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| -84 2.3.3.29 Primary Component Cooling Water System ................................ 2
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| -84 2.3.3.30 Radiation Monitoring System....................................................... 2
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| -87 2.3.3.31 Reactor Makeup Water System ................................................... 2
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| -88 2.3.3.32 Release Recovery System .......................................................... 2
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| -89 2.3.3.33 Resin Sluicing System................................................................. 2
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| -89 2.3.3.34 Roof Drains System .................................................................... 2-89 2.3.3.35 Sample System ........................................................................... 2
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| -91 2.3.3.36 Screen Wash System .................................................................. 2
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| -92 2.3.3.37 Service Water System ................................................................. 2
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| -92 2.3.3.38 Service Water Pump House Air Handling System ....................... 2
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| -94 2.3.3.39 Spent Fuel Pool Cooling System ................................................. 2
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| -95 2.3.3.40 Switchyard .................................................................................. 2
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| -98 2.3.3.41 Valve Stem Leak
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| -off System ....................................................... 2
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| -99 2.3.3.42 Vent Gas System ...................................................................... 2
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| -100 2.3.3.43 Waste Gas System ................................................................... 2
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| -101 2.3.3.44 Waste Processing Liquid System .............................................. 2
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| -102 2.3.3.45 Waste Processing Liquid Drains System ................................... 2
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| -103 2.3.4 Steam and Power Conversion Systems .................................................... 2
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| -105 2.3.4.1 Auxiliary Steam System ............................................................ 2
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| -106 Table of Contents vi 2.3.4.2 Auxiliary Steam Condensate System ........................................ 2
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| -107 2.3.4.3 Auxiliary Steam Heating System ............................................... 2
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| -108 2.3.4.4 Circulating Water System .......................................................... 2
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| -108 2.3.4.5 Condensate System .................................................................. 2
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| -108 2.3.4.6 Feedwater System .................................................................... 2
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| -110 2.3.4.7 Main Steam System (Includes Main Steam Drain System) ........ 2
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| -112 2.3.4.8 Steam Generator Blowdown System ......................................... 2
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| -113 2.4 Scoping and Screening Results: Structures ......................................................... 2
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| -114 2.4.1 Buildings, Structures within License Renewal ........................................... 2
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| -115 2.4.1.1 Summary of Technical Information in the Application ................ 2
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| -115 2.4.1.2 Staff Evaluation ......................................................................... 2
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| -116 2.4.1.3 Conclusion ................................................................................ 2
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| -118 2.4.2 Containment Structures ............................................................................ 2
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| -118 2.4.2.1 Summary of Technical Information in the Application ................ 2
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| -118 2.4.2.2 Conclusion ................................................................................ 2
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| -119 2.4.3 Fuel Handling and Overhead Cranes ........................................................ 2
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| -119 2.4.3.1 Summary of Technical Information in the Application ................ 2
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| -119 2.4.3.2 Conclusion ................................................................................ 2
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| -119 2.4.4 Miscellaneous Yard Structures .................................................................. 2
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| -119 2.4.4.1 Summary of Technical Information in the Application ................ 2
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| -119 2.4.4.2 Conclusion ................................................................................ 2
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| -120 2.4.5 Primary Structures .................................................................................... 2
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| -120 2.4.5.1 Summary of Technical Information in the Application ................ 2
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| -120 2.4.5.2 Conclusion ................................................................................ 2
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| -121 2.4.6 Supports ................................................................................................... 2
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| -121 2.4.6.1 Summary of Technical Information in the Application ................ 2
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| -121 2.4.6.2 Staff Evaluation ......................................................................... 2
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| -122 2.4.6.3 Conclusion ................................................................................ 2
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| -123 2.4.7 Turbine Building ........................................................................................ 2
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| -123 2.4.7.1 Summary of Technical Information in the Application ................ 2
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| -123 2.4.7.2 Conclusion ................................................................................ 2
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| -123 Table of Contents vii 2.4.8 Water Control Structures ........................................................................... 2
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| -124 2.4.8.1 Summary of Technical Information in the Application ................ 2
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| -124 2.4.8.2 Conclusion ................................................................................ 2
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| -124 2.5 Scoping and Screening Results: Electrical and Instrumentation and Control Systems................................................................................................................ 2
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| -124 2.5.1 Electrical Component Groups ................................................................... 2
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| -125 2.5.1.1 Summary of Technical Information in the Application ................ 2
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| -125 2.5.1.2 Staff Evaluation ......................................................................... 2
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| -126 2.5.1.3 Conclusion ................................................................................ 2
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| -127 2.6 Conclusion for Scoping and Screening ................................................................. 2
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| -127 SECTION 3 AGING MANAGEMENT REVIEW RESULTS .................................................. 3
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| -1 3.0 Applicant's Use of the Generic Aging Lessons Learned Report ................................ 3
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| -1 3.0.1 Format of the License Renewal Application .................................................. 3
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| -2 3.0.1.1 Overview of Table 1's .................................................................... 3
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| -2 3.0.1.2 Overview of Table 2's .................................................................... 3
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| -3 3.0.2 Staff's Review Process ................................................................................. 3
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| -4 3.0.2.1 Review of Aging Management Programs ...................................... 3
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| -5 3.0.2.2 Review of Aging Management Review Results ............................. 3
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| -6 3.0.2.3 Updated Final Safety Analysis Report Supplement ....................... 3
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| -7 3.0.2.4 Documentation and Documents Reviewed .................................... 3
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| -7 3.0.3 Aging Management Programs ....................................................................... 3
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| -7 3.0.3.1 Aging Management Programs Consistent with the Generic Aging Lessons Learned Report ................................................... 3
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| -11 3.0.3.2 Aging Management Programs Consistent with the GALL Report with Exceptions or Enhancements ................................... 3
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| -57 3.0.3.3 Aging Management Programs Not Consistent with or Not Addressed in the GALL Report .................................................. 3
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| -186 3.0.3.4 Aging Management Program Related to Interim Staff Guidance Issuance ................................................................... 3
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| -243 3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs .................................................................................................. 3
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| -249 3.0.4.1 Summary of Technical Information in the Application ................ 3
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| -249 3.0.4.2 Staff Evaluation ......................................................................... 3
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| -249 Table of Contents viii 3.0.4.3 Conclusion ................................................................................ 3
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| -250 3.0.5 Operating Experience ............................................................................... 3
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| -250 3.0.5.1 Summary of Technical Information in the Application ................ 3
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| -250 3.0.5.2 Staff Evaluation ......................................................................... 3
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| -250 3.0.5.3 UFSAR Supplement .................................................................. 3
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| -257 3.0.5.4 Conclusion ................................................................................ 3
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| -259 3.1 Aging Management of Reactor Coolant System ................................................... 3
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| -259 3.1.1 Summary of Technical Information in the Application ................................ 3
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| -259 3.1.2 Staff Evaluation ......................................................................................... 3
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| -259 3.1.2.1 Aging Management Review Results That Are Consistent with the GALL Report ....................................................................... 3
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| -276 3.1.2.2 Aging Management Review Results That Are Consistent with the GALL Report for Which Further Evaluation is Recommended .......................................................................... 3
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| -286 3.1.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report ................................................................... 3
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| -304 3.1.3 Conclusion ................................................................................................ 3
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| -308 3.2 Aging Management of Engineered Safety Features .............................................. 3
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| -308 3.2.1 Summary of Technical Information in the Application ................................ 3
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| -308 3.2.2 Staff Evaluation ......................................................................................... 3
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| -308 3.2.2.1 Aging Management Review Results Consistent with the GALL Report ............................................................................. 3
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| -318 3.2.2.2 Aging Management Review Results Consistent with the GALL Report for Which Further Evaluation is Recommended ... 3
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| -326 3.2.2.3 Aging Management Review Results Not Consistent with or Not Addressed in the GALL Report ........................................... 3-339 3.2.3 Conclusion ................................................................................................ 3
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| -342 3.3 Aging Management of Auxiliary Systems .............................................................. 3
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| -342 3.3.1 Summary of Technical Information in the Application ................................ 3
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| -343 3.3.2 Staff Evaluation ......................................................................................... 3
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| -344 3.3.2.1 Aging Management Review Results Consistent with the GALL Report ............................................................................. 3
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| -361 Table of Contents ix 3.3.2.2 Aging Management Review Results Consistent with the GALL Report for Which Further Evaluation is Recommended ... 3
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| -385 3.3.2.3 Aging Management Review Results Not Consistent with or Not Addressed in the GALL Report ........................................... 3
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| -413 3.3.3 Conclusion ................................................................................................ 3
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| -469 3.4 Aging Management of Steam and Power Conversion Systems ............................ 3
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| -469 3.4.1 Summary of Technical Information in the Application ................................ 3
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| -470 3.4.2 Staff Evaluation ......................................................................................... 3
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| -470 3.4.2.1 Aging Management Review Results Consistent with the GALL Report ............................................................................. 3
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| -477 3.4.2.2 Aging Management Review Results Consistent with the GALL Report for Which Further Evaluation Is Recommended ... 3
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| -492 3.4.2.3 Aging Management Review Results Not Consistent with or Not Addressed in the GALL Report ........................................... 3
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| -504 3.4.3 Conclusion ................................................................................................ 3
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| -516 3.5 Aging Management of Containments, Structures, and Component Supports ........ 3
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| -516 3.5.1 Summary of Technical Information in the Application ................................ 3
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| -517 3.5.2 Staff Evaluation ......................................................................................... 3
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| -517 3.5.2.1 Aging Management Review Results Consistent with the GALL Report ............................................................................. 3
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| -530 3.5.2.2 Aging Management Review Results Consistent with the GALL Report for Which Further Evaluation Is Recommended ... 3
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| -540 3.5.2.3 Aging Management Review Results Not Consistent with or Not Addressed in the GALL Report ........................................... 3
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| -559 3.5.3 Conclusion ................................................................................................ 3
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| -565 3.6 Aging Management of Electrical and Instrumentation and Controls ...................... 3
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| -565 3.6.1 Summary of Technical Information in the Application ................................ 3
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| -566 3.6.2 Staff Evaluation ......................................................................................... 3
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| -566 3.6.2.1 Aging Management Review Results Consistent with the GALL Report ............................................................................. 3
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| -569 3.6.2.2 Aging Management Review Results Consistent with th e GALL Report for which Further Evaluation Is Recommended.... 3
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| -571 Table of Contents x 3.6.2.3 Aging Management Review Results Not Consistent with or Not Addressed in the GALL Report ........................................... 3
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| -572 3.6.3 Conclusion ................................................................................................ 3
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| -575 3.7 Conclusion for AMR Results ................................................................................. 3
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| -575 SECTION 4 TIME-LIMITED AGING ANALYSES ................................................................ 4
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| -1 4.1 Identification of Time
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| -Limited Aging Analyses ........................................................... 4
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| -1 4.1.1 Summary of Technical Information in the Application .................................... 4
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| -1 4.1.2 Staff Evaluation ............................................................................................. 4
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| -1 4.1.2.1 Evaluation of the Applicant's Identification of TLAAs ..................... 4
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| -1 4.1.2.2 Evaluation of the Applicant's Identification of those Exemptions in the CLB that are Based on TLAAs ......................... 4
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| -3 4.1.3 Conclusion .................................................................................................... 4
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| -4 4.2 Reactor Pressure Vessel Neutron Embrittlement ...................................................... 4
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| -4 4.2.1 Reactor Pressure Vessel Fluence ................................................................. 4
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| -5 4.2.1.1 Summary of Technical Information in the Application .................... 4
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| -5 4.2.1.2 Staff Evaluation ............................................................................. 4
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| -6 4.2.1.3 UFSAR Supplement ...................................................................... 4
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| -7 4.2.1.4 Conclusion .................................................................................... 4
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| -7 4.2.2 Upper Shelf Energy Analyses ....................................................................... 4
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| -8 4.2.2.1 Summary of Technical Information in the Application .................... 4
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| -8 4.2.2.2 Staff Evaluation ............................................................................. 4
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| -8 4.2.2.3 UFSAR Supplement ...................................................................... 4
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| -9 4.2.2.4 Conclusion .................................................................................... 4
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| -9 4.2.3 Pressurized Thermal Shock Analyses ........................................................... 4
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| -9 4.2.3.1 Summary of Technical Information in the Application .................... 4
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| -9 4.2.3.2 Staff Evaluation ........................................................................... 4
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| -10 4.2.3.3 UFSAR Supplement .................................................................... 4
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| -11 4.2.3.4 Conclusion .................................................................................. 4
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| -11 4.2.4 Reactor Vessel Pressure
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| -Temperature Limit and Low
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| -Temperature Overpressure Protection Analyses .............................................................. 4
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| -11 4.2.4.1 Summary of Technical Information in the Application .................. 4
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| -11 4.2.4.2 Staff Evaluation ........................................................................... 4
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| -12 Table of Contents xi 4.2.4.3 UFSAR Supplement .................................................................... 4
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| -13 4.2.4.4 Conclusion .................................................................................. 4
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| -13 4.3 Metal Fatigue Analysis of Piping and Components ................................................. 4
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| -13 4.3.1 Nuclear Steam Supply System Pressure Vessel and Component Fatigue Analyses (RPV and RPV Component Fatigue Analyses)................ 4
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| -14 4.3.1.1 Summary of Technical Information in the Application .................. 4
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| -14 4.3.1.2 Staff Evaluation ........................................................................... 4
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| -14 4.3.1.3 UFSAR Supplement .................................................................... 4
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| -19 4.3.1.4 Conclusion .................................................................................. 4
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| -20 4.3.2 Supplementary ASME Section III, Class 1 Piping and Component Fatigue Analysis .......................................................................................... 4
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| -20 4.3.2.1 Absence of a TLAA for Thermal Stresses in Piping Connected to RCSs: NRC Bulletin 88
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| -08 ................................... 4
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| -20 4.3.2.2 NRC Bulletin 88
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| -11, PSL Thermal Stratification .......................... 4
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| -22 4.3.3 Reactor Vessel Internals Aging Management.............................................. 4
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| -24 4.3.3.1 Summary of Technical Information in the Application .................. 4
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| -24 4.3.3.2 Staff Evaluation ........................................................................... 4
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| -24 4.3.3.3 UFSAR Supplement .................................................................... 4
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| -29 4.3.3.4 Conclusion .................................................................................. 4
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| -30 4.3.4 Environmentally
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| -Assisted Fatigue Analysis ................................................. 4
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| -30 4.3.4.1 Summary of Technical Information in the Application .................. 4
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| -30 4.3.4.2 Staff Evaluation ........................................................................... 4
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| -31 4.3.4.3 UFSAR Supplement .................................................................... 4
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| -35 4.3.4.4 Conclusion .................................................................................. 4
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| -36 4.3.5 Steam Generator Tube, Loss of Material and Fatigue Usage from Fl ow-Induced Vibration ............................................................................... 4
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| -37 4.3.5.1 Summary of Technical Information in the Application .................. 4
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| -37 4.3.5.2 Staff Evaluation ........................................................................... 4
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| -37 4.3.5.3 UFSAR Supplement .................................................................... 4
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| -39 4.3.5.4 Conclusion .................................................................................. 4
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| -4 0 4.3.6 Absence of TLAAs for Fatigue Crack Growth, Fracture Mechanics Stability, or Corrosion Analysis Supporting Repair of Alloy 600 Materials .... 4
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| -40 4.3.6.1 Summary of Technical Information in the Application .................. 4
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| -40 Table of Contents xii 4.3.6.2 Staff Evaluation ........................................................................... 4
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| -40 4.3.6.3 UFSAR Supplement .................................................................... 4
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| -41 4.3.6.4 Conclusion .................................................................................. 4
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| -41 4.3.7 Non-Class 1 Component Fatigue Analyses ................................................. 4
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| -42 4.3.7.1 Summary of Technical Information in the Application .................. 4
| |
| -42 4.3.7.2 Staff Evaluation ........................................................................... 4
| |
| -42 4.3.7.3 UFSAR Supplement .................................................................... 4
| |
| -44 4.3.7.4 Conclusion .................................................................................. 4
| |
| -44 4.4 Environmental Qualification (EQ) of Electrical Equipment ....................................... 4
| |
| -44 4.4.1 Summary of Technical Information in the Application .................................. 4
| |
| -44 4.4.2 Staff Evaluation ........................................................................................... 4
| |
| -45 4.4.3 UFSAR Supplement .................................................................................... 4
| |
| -46 4.4.4 Conclusion .................................................................................................. 4
| |
| -46 4.5 Concrete Containment Tendon Pre
| |
| -stress .............................................................. 4
| |
| -46 4.5.1 Summary of Technical Information in the Application .................................. 4
| |
| -46 4.5.2 Staff Evaluation ........................................................................................... 4
| |
| -46 4.5.3 UFSAR Supplement .................................................................................... 4
| |
| -47 4.5.4 Conclusion .................................................................................................. 4
| |
| -47 4.6 Containment Liner Plate Fatigue Usage and Containment Penetration Pressurization Cycles ............................................................................................. 4
| |
| -47 4.6.1 Containment Liner Plate Fatigue Usage ...................................................... 4
| |
| -47 4.6.1.1 Summary of Technical Information in the Application .................. 4
| |
| -47 4.6.1.2 Staff Evaluation ........................................................................... 4
| |
| -48 4.6.1.3 UFSAR Supplement .................................................................... 4
| |
| -49 4.6.1.4 Conclusion .................................................................................. 4
| |
| -49 4.6.2 Pressurization Cycles: Personnel Airlock, Equipment Hatch, and Fuel Transfer Tube Assembly Absence of TLAA for Containment Penetrations ................................................................................................ 4
| |
| -49 4.6.2.1 Summary of Technical Information in the Application ..................
| |
| 4-49 4.6.2.2 Staff Evaluation ........................................................................... 4
| |
| -50 4.6.2.3 UFSAR Supplement .................................................................... 4
| |
| -52 4.6.2.4 Conclusion .................................................................................. 4
| |
| -52 Table of Contents xiii 4.7 Other Plant
| |
| -Specific TLAAs .................................................................................... 4
| |
| -52 4.7.1 Absence of a TLAA for Reactor Pressure Vessel Underclad Cracking Analyses ..................................................................................................... 4
| |
| -52 4.7.1.1 Summary of Technical Information in the Application .................. 4
| |
| -52 4.7.1.2 Staff Evaluation ........................................................................... 4
| |
| -53 4.7.1.3 UFSAR Supplement .................................................................... 4
| |
| -53 4.7.1.4 Conclusion .................................................................................. 4
| |
| -53 4.7.2 Reactor Coolant Pump Flywheel Fatigue Crack Growth Analyses .............. 4
| |
| -53 4.7.2.1 Summary of Technical Information in the Application .................. 4
| |
| -53 4.7.2.2 Staff Evaluation ........................................................................... 4
| |
| -54 4.7.2.3 UFSAR Supplement .................................................................... 4
| |
| -56 4.7.2.4 Conclusion .................................................................................. 4
| |
| -56 4.7.3 Leak-Before-Break Analyses ....................................................................... 4
| |
| -57 4.7.3.1 Summary of Technical Information in the Application .................. 4
| |
| -57 4.7.3.2 Staff Evaluation ........................................................................... 4
| |
| -57 4.7.3.3 UFSAR Supplement .................................................................... 4
| |
| -60 4.7.3.4 Conclusion .................................................................................. 4
| |
| -60 4.7.4 High-Energy Line Break Postulation Based on Cumulative Usage Factor ... 4
| |
| -60 4.7.4.1 Summary of Technical Information in the Application .................. 4-60 4.7.4.2 Staff Evaluation ........................................................................... 4
| |
| -60 4.7.4.3 UFSAR Supplement .................................................................... 4
| |
| -62 4.7.4.4 Conclusion .................................................................................. 4
| |
| -62 4.7.5 Fuel Transfer Tube Bellows Design Cycles ................................................. 4
| |
| -63 4.7.5.1 Summary of Technical Information in the Application .................. 4-63 4.7.5.2 Staff Evaluation ........................................................................... 4
| |
| -63 4.7.5.3 UFSAR Supplement .................................................................... 4
| |
| -64 4.7.5.4 Conclusion .................................................................................. 4
| |
| -64 4.7.6 Crane Load Cycle Limits ............................................................................. 4
| |
| -65 4.7.6.1 Polar Gantry Crane ..................................................................... 4
| |
| -65 4.7.6.2 Cask Handling Crane .................................................................. 4
| |
| -66 4.7.7 Service Level 1 Coatings Qualification ........................................................ 4
| |
| -67 4.7.7.1 Summary of Technical Information in the Application .................. 4
| |
| -67 4.7.7.2 Staff Evaluation ........................................................................... 4
| |
| -68 Table of Contents xiv 4.7.7.3 UFSAR Supplement .................................................................... 4
| |
| -69 4.7.7.4 Conclusion .................................................................................. 4
| |
| -69 4.7.8 Absence of a TLAA for Reactor Coolant Pump: Code Case N
| |
| -481 ............ 4-69 4.7.8.1 Summary of Technical Information in the Application .................. 4
| |
| -69 4.7.8.2 Staff Evaluation ........................................................................... 4
| |
| -69 4.7.8.3 UFSAR Supplement .................................................................... 4
| |
| -70 4.7.8.4 Conclusion .................................................................................. 4
| |
| -70 4.7.9 Canopy Seal Clamp Assemblies ................................................................. 4
| |
| -70 4.7.9.1 Summary of Technical Information in the Application .................. 4
| |
| -70 4.7.9.2 Staff Evaluation ........................................................................... 4-71 4.7.9.3 UFSAR Supplement .................................................................... 4
| |
| -73 4.7.9.4 Conclusion .................................................................................. 4
| |
| -73 4.7.10 Hydrogen Analyzer ..................................................................................... 4
| |
| -73 4.7.10.1 Summary of Technical Information in the Application .................. 4
| |
| -73 4.7.10.2 Staff Evaluation ........................................................................... 4
| |
| -73 4.7.10.3 UFSAR Supplement .................................................................... 4
| |
| -74 4.7.10.4 Conclusion .................................................................................. 4
| |
| -75 4.7.11 Mechanical Equipment Qualification ........................................................... 4
| |
| -75 4.7.11.1 Summary of Technical Information in the Application .................. 4
| |
| -75 4.7.11.2 Staff Evaluation ........................................................................... 4
| |
| -75 4.7.11.3 UFSAR Supplement .................................................................... 4
| |
| -78 4.7.11.4 Conclusion .................................................................................. 4
| |
| -78 4.7.12 Absence of a TLAA for Metal Corrosion Allowances and Corrosion Effects 4-78 4.7.12.1 Summary of Technical Information in the Application .................. 4
| |
| -78 4.7.12.2 Staff Evaluation ........................................................................... 4
| |
| -78 4.7.12.3 UFSAR Supplement .................................................................... 4
| |
| -79 4.7.12.4 Conclusion .................................................................................. 4
| |
| -80 4.7.13 Absence of a TLAA for Inservice Flaw Growth Analyses that Demonstrate Structural Stability for 40 Years .............................................. 4
| |
| -80 4.7.13.1 Summary of Technical Information in the Application .................. 4
| |
| -80 Table of Contents xv 4.7.13.2 Staff Evaluation ........................................................................... 4
| |
| -80 4.7.13.3 UFSAR ........................................................................................ 4
| |
| -82 4.7.13.4 Conclusion .................................................................................. 4
| |
| -82 4.7.14 Diesel Generator Thermal Cycle Evaluation ................................................ 4
| |
| -82 4.7.14.1 Summary of Technical Information in the Application .................. 4
| |
| -82 4.7.14.2 Staff Evaluation ........................................................................... 4
| |
| -83 4.7.14.3 UFSAR Supplement .................................................................... 4
| |
| -84 4.7.14.4 Conclusion .................................................................................. 4
| |
| -84 4.7.15 Steam Generator Tube Wall Wear from Flow
| |
| -Induced Vibration ................. 4
| |
| -84 4.7.15.1 Summary of Technical Information in the Application .................. 4-84 4.7.15.2 Staff Evaluation ........................................................................... 4
| |
| -85 4.7.15.3 UFSAR Supplement .................................................................... 4
| |
| -86 4.7.15.4 Conclusion .................................................................................. 4
| |
| -87 4.8 Conclusion .............................................................................................................. 4
| |
| -87 SECTION 5 REVIEW BY THE ADVISORY COMMITTEE ON REACTOR SAFEGUARDS ................................................................................................ 5
| |
| -1 SECTION 6 CONCLUSION ................................................................................................. 6
| |
| -1 APPENDIX A SEABROOK STATION LICENSE RENEWAL COMMITMENTS .................. A
| |
| -1 APPENDIX B CHRONOLOGY ............................................................................................ B
| |
| -1 APPENDIX C PRINCIPAL CONTRIBUTORS ..................................................................... C
| |
| -1 APPENDIX D REFERENCES ............................................................................................. D
| |
| -1
| |
| | |
| xvii LIST OF TABLES Table 1.4-1. Current Interim Staff Guidance .......................................................................1
| |
| -7 Table 3.0-1. Aging Management Programs ........................................................................3
| |
| -7 Table 3.1-1. Staff Evaluation for Reactor Vessel, Reactor Vessel Internals, and Reactor Coolant System Components in the GALL Report ........................ 3
| |
| -260 Table 3.2-1. Staff Evaluation for Engineered Safety Features Systems Components in the GALL Report ....................................................................................3
| |
| -309 Table 3.3-1. Staff Evaluation for Auxiliary System Components in the GALL Report...... 3
| |
| -345 Table 3.4-1. Staff Evaluation for Steam and Power Conversion Systems Components in the GALL Report ...............................................................3
| |
| -471 Table 3.5-1. Staff Evaluation for Structures and Component Supports Components in the GALL Report ....................................................................................3
| |
| -518 Table 3.6-1. Staff Evaluation for Electrical and Instrumentation and Controls in the GALL Report ..............................................................................................3
| |
| -566 Table A.1-1. Appendix A: Seabrook Station License Renewal Commitments ................... A
| |
| -2 Table B.1-1. Appendix B: Chronology ..............................................................................
| |
| B-1 Table C.1-1. Appendix C: Principal Contributors ............................................................... C
| |
| -1
| |
| | |
| xix ABBREVIATION AC alternating current ACI American Concrete Institute ACRS Advisory Committee on Reactor Safeguards ADAMS Agencywide Documents Access and Management System AERM aging effect requiring management AFW auxiliary feedwater AMP aging management program AMR aging management review AMS ATWS mitigation system ANS American Nuclear Society ANSI American National Standards Institute APCSB Auxiliary and Power Conversion Systems Branch AR action request ART adjusted reference temperature ASCE American Society of Civil Engineers ASFPC alternate spent fuel pool cooling ASM American Society for Metals ASME American Society of Mechanical Engineers ASR alkali-silica reaction ASRMP Alkali-Silica Reaction Monitoring Program AST alternate source term ASTM American Society for Testing and Materials ATWS anticipated transient without scram AWS American Welding Society AWWA American Water Works Association B&PV boiler and pressure vessel B&W Babcock & Wilcox Company B10 boron-10 BDMP Building Deformation Monitoring Program BTP Branch Technical Position BWR boiling-water reactor C Celsius CASS cast austenitic stainless steel CC primary component cooling water system CCI Combined Cracking Index CEB Containment Enclosure Building CEA control element assembly CEVA Containment Enclosure Ventilation Area cfm cubic feet per minute CFR Code of Federal Regulations CI cracking index CISI Containment lnservice Inspection
| |
| | |
| CL chlorination system CLB current licensing basis cm 2 squared centimeter
| |
| | |
| xxi CMTR certified material test record CO 2 carbon dioxide CR condition report CRD control rod drive CRDM control rod drive mechanism CS containment spray CSR cable spreading room CSS containment spray system CST condensate storage tank Cu copper CUF cumulative fatigue usage CUF en environmentally correct CUF CuNi copper nickel CVCS chemical and volume control system DBA design-basis accident DBD design-basis document DBE design-basis event DCI division of component integrity EAF environmentally
| |
| -assisted fatigue ECCS emergency core cooling system EDB equipment database EDG emergency diesel generator EFPH emergency feedwater pump house EFPD effective full power days EFPY effective full power years EFW emergency feedwater EOL end-of-life EPA Environmental Protection Agency Emergency Feedwater Pump House Air Handling EPRI Electric Power Research Institute EQ environmental qualification ER environmental report ESF engineered safety feature ESFAS engineered safety features actuation system F Fahrenheit FA fire area F en environmental life correction factor FERC Federal Energy Regulatory Commission FHWA Federal Highway Administration FIV flow-induced vibration FPL Florida Power and Light Company
| |
| | |
| Abbreviations xxii FR Federal Register FRN Federal Register Notice FSAR final safety analysis report ft foot Abbreviations FWST fire protection water storage tanks gal. gallon GALL Generic Aging Lessons Learned GDC general design criterion GEIS generic environmental impact statement GL generic letter gpm gallons per minute GSI generic safety issue GSU generator step
| |
| -up H 2 hydrogen HELB high-energy line break HLSN hot leg surge line nozzle HPSI high-pressure safety injection HVAC heating, ventilation, and air conditioning HW hot water heating I&C instrumentation and control IASCC irradiation
| |
| -assisted stress corrosion cracking IEEE Institute of Electrical and Electronic Engineers IGSCC intergranular stress corrosion cracking IN information notice INPO Institute of Nuclear Power Operation IPA integrated plant assessment IR inspection report ISA independent safety analysis ISG interim staff guidance ISI inservice inspection ksi kips per square inch kV kilovolt L liter lb pound LBB leak-before-break LOCA loss-of-coolant accident LOOP loss of offsite power LRA license renewal application
| |
| | |
| xxiii LSTP large-scale testing program LTOP low-temperature overpressure protection MC metal containment MEA material, environment, and aging effects MEAP material, environment, aging effects, and aging management program MEB metal enclosed bus MEQ mechanical equipment qualification MeV million electron
| |
| -volts mg milligram MIC microbiologically
| |
| -influenced corrosion MRP Materials Reliability Program MRule Maintenance Rule MSIP mechanical stress improvement process MSL mean sea level MWt megawatt thermal n/cm 2 neutrons per square centimeter NACE National Association of Corrosion Engineers NaOH sodium hydroxide NEI Nuclear Energy Institute NextEra NextEra Energy Seabrook, LLC NFPA National Fire Protection Association NNS non-nuclear safety NPS nominal pipe size NRC U.S. Nuclear Regulatory Commission NRR Office of Nuclear Reactor Regulation NSAS non-safety affecting safety NSSS nuclear steam supply system OBE operating basis earthquake ODSCC outside-diameter stress corrosion cracking OEM original equipment manufacturer OTSG once-through steam generator P&ID piping and instrumentation diagram PAH primary auxiliary building air handling ppb parts per billion ppm parts per million PRT penetration resistance test psi pounds per square inch psig pounds per square inch gauge PSL pressurizer surge line PSN pressurizer surge nozzle
| |
| | |
| Abbreviations xxiv P-T pressure-temperature PTS pressurized thermal shock PVC polyvinyl chloride PVDF polyvinylidene fluoride PWR pressurized
| |
| -water reactor PWSCC primary water stress corrosion cracking QA quality assurance QAP Quality Assurance Program Abbreviations RAI request for additional information RAT reserve auxiliary transformer RCCA rod cluster control assembly RCIC reactor core isolation cooling RCP reactor coolant pump RCPB reactor coolant pressure boundary RCS reactor coolant system RFO refueling outage RIC recurring internal corrosion RG regulatory guide RH residual heat removal RIS regulatory issue summary RM radiation monitoring system RPS reactor protection system RPV reactor pressure vessel RS resin sluicing system RTD resistance temperature detectors RT NDT nil-ductility reference temperature RTPTS PTS reference temperature RV reactor vessel RVI reactor vessel internals RVID Reactor Vessel Integrity Database RWST refueling water storage tank SBO station blackout SC structure and component SCC stress corrosion cracking SCFM standard cubic feet per minute Seabrook Seabrook Station, Unit No. 1 SE safety evaluation SER safety evaluation report SF 6 sulfur hexafluoride SFP spent fuel pool SG steam generator SI safety injection SO 2 sulfur dioxide
| |
| | |
| xxv SOC Statements of Consideration SPU stretch power uprate SRBE Snap-Ring Borehole Extensometer SRP-LR Standard Review Plan
| |
| -License Renewal SSC system, structure, and component SSE safe shutdown earthquake SSPS solid state protection system The Rule Requirements for Renewal of Operating Licenses for Nuclear Power Plants TLAA time-limited aging analysis TS technical specification TSTF technical specification task force UAT unit auxiliary transformers UFSAR updated final safety analysis report USE upper-shelf energy UT ultrasonic testing V volt WCAP Westinghouse Commercial Atomic Power WG waste gas system WL waste processing liquid system WLD waste processing liquid drains system WOG Westinghouse Owners Group Zn zinc
| |
| | |
| 1-1 SECTION 1 INTRODUCTION AND GENERAL DISCUSSION
| |
| | |
| ===1.1 Introduction===
| |
| This document is a safety evaluation report (SER) on the license renewal application (LRA) for Seabrook Station, Unit No. 1 (Seabrook), as filed by NextEra Energy Seabrook, LLC (NextEra or the applicant). By letter dated May 25, 2010, the applicant submitted its application to the U.S. Nuclear Regulatory Commission (NRC) for renewal of the Seabrook operating license for an additional 20 years. The NRC staff (the staff) prepared this report to summarize the results of its safety review of the LRA for compliance with Title 10 of the Code of Federal Regulations Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants" (10 CFR Part 54). The NRC project manager for the license renewal review is Ms. Evelyn Gettys, who may be contacted by telephone at 301
| |
| -415-3306, or by electronic mail at Evelyn.Gettys@nrc.gov. Alternatively, written correspondence may be sent to the following address: Division of Materials and License Renewal U.S. Nuclear Regulatory Commission Washington, D.C. 205 55-0001 Attention: Evelyn Gettys, Mail Stop O11E1 By letter dated May 25, 2010, the applicant requested renewal of the operating license issued under Section 103 (Operating License No. NPF
| |
| -86) of the Atomic Energy Act of 1954, as amended, for Seabrook for a period of 20 years beyond its current expiration at midnight on March 15, 2030.
| |
| Seabrook is located in Seabrook Township, Rockingham County, New Hampshire, on the western shore of Hampton Harbor, 2 miles west of the Atlantic Ocean. The NRC issued a zero-power license for Seabrook in October 1986 and a full
| |
| -power operating license was subsequently granted on March 15, 1990. Seabrook employs a pressurized
| |
| -water reactor (PWR) housed in a steel lined reinforced concrete containment structure which is enclosed by a reinforced concrete containment enclosure structure. The licensed power output was initially 3,411 megawatts thermal (MWt); however, after implementing two power uprates, the rated thermal power has been increased to 3,648 MWt. The updated final safety analysis report (UFSAR) contains details of the plant and the site.
| |
| The license renewal process consists of two concurrent reviews, a technical review of safety issues and an environmental review. The NRC regulations in 10 CFR Part 54 and 10 CFR Part 51, "Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions," respectively, set forth requirements for these reviews. The safety review for the Seabrook license renewal is based on the applicant's LRA and on its responses to the staff's requests for additional information (RAIs). The applicant supplemented the LRA and provided clarifications through its responses to the staff's RAIs and other docketed correspondence. Unless otherwise noted, the staff reviewed and considered information submitted through July 2018. The staff reviewed information received after that date depending on the stage of the Introduction and General Discussion 1-2 safety review and the volume and complexity of the information, relative to the issuance of this SER update.
| |
| The public may view the LRA and all pertinent information and materials, including the UFSAR, at the NRC Public Document Room, located on the first floor of One White Flint North, 11555 Rockville Pike, Rockville, MD 20852
| |
| -2738 (301-415-4737 or 800
| |
| -397-4209). The LRA may also be viewed at Seabrook Library located at 25 Liberty Lane, Seabrook, NH 03874 or the Amesbury Public Library located at 149 Main Street, Amesbury, MA 01913. In addition, the public may find the LRA, as well as materials related to the license renewal review, on the NRC website at http://www.nrc.gov.
| |
| This SER summarizes the results of the staff's safety review of the LRA and describes the technical details considered in evaluating the safety aspects of the proposed operation of Seabrook for an additional 20 years beyond the term of the current operating license. The staff reviewed the LRA in accordance with NRC regulations and the guidance in NUREG
| |
| -1800, Revision 2, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants" (SRP
| |
| -LR), dated December 2010.
| |
| SER Sections 2 through 4 address the staff's evaluation of license renewal issues considered during the review of the application. SER Section 5 is reserved for the report of the Advisory Committee on Reactor Safeguards (ACRS). The conclusions of this SER are in Section 6.
| |
| SER Appendix A is a table showing the applicant's commitments related to the renewal of the operating licenses. SER Appendix B is a chronology of the principal correspondence betwe en the staff and the applicant regarding the LRA review. SER Appendix C is a list of principal contributors to the SER and Appendix D is a bibliography of the references in support of the staff's review.
| |
| In accordance with 10 CFR Part 51, the staff prepared a plant
| |
| -specific supplement to NUREG
| |
| -1437, "Generic Environmental Impact Statement for License Renewal of Nuclear Plants (GEIS)." This supplement discusses the environmental considerations for license renewal for Seabrook. The staff published the final plant-specific GEIS Supplement "Generic Environmental Impact Statement for License Renewal of Nuclear Plants: Supplement 46 Regarding Seabrook Station," in July 2015.
| |
| | |
| ===1.2 License===
| |
| Renewal Background Pursuant to the Atomic Energy Act of 1954, as amended, and NRC regulations, operating licenses for commercial power reactors are issued for 40 years and can be renewed for up to 20 additional years. The original 40
| |
| -year license term was selected based on economic and antitrust considerations rather than on technical limitations; however, some individual plant and equipment designs may have been engineered for an expected 40
| |
| -year service life.
| |
| In 1982, the staff anticipated interest in license renewal and held a workshop on nuclear power plant aging. This workshop led the NRC to establish a comprehensive program plan for nuclear plant aging research. From the results of that research, a technical review group concluded that many aging phenomena are readily manageable and pose no technical issues precluding life extension for nuclear power plants. In 1986, the staff published a request for comment on a policy statement that would address major policy, technical, and procedural issues related to license renewal for nuclear power plants.
| |
| | |
| Introduction and General Discussion 1-3 In 1991, the staff published 10 CFR Part 54, the License Renewal Rule (Volume 56, page 64943, of the Federal Register (56 FR 64943), dated December 13, 1991). The staff participated in an industry
| |
| -sponsored demonstration program to apply 10 CFR Part 54 to a pilot plant and to gain the experience necessary to develop implementation guidance. To establish a scope of review for license renewal, 10 CFR Part 54 defined age
| |
| -related degradation unique to license renewal. However, during the demonstration program, the staff found that adverse aging effects on plant systems and components are managed during the period of initial license and that the scope of the review did not allow sufficient credit for management programs, particularly the implementation of 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," which regulates management of plant
| |
| -aging phenomena. As a result of this finding, the staff amended 10 CFR Part 54 in 1995. As published May 8, 1995, in 60 FR 22461, amended 10 CFR Part 54 establishes a regulatory process that is simpler, more stable, and more predictable than the previous 10 CFR Part 54. In particular, as amended, 10 CFR Part 54 focuses on the management of adverse aging effects rather than on the identification of age
| |
| -related degradation unique to license renewal. The staff made these rule changes to ensure that important systems, structures, and components (SSCs) will continue to perform their intended functions during the period of extended operation. In addition, the amended 10 CFR Part 54 clarifies and simplifies the integrated plant assessment (IPA) process to be consistent with the revised focus on passive, long
| |
| -lived structures and components (SCs).
| |
| Concurrent with these initiatives, the staff pursued a separate rulemaking effort (61 FR 28467, June 5, 1996) and amended 10 CFR Part 51 to focus the scope of the review of environmental impacts of license renewal in order to fulfill NRC responsibilities under the National Environmental Policy Act of 1969 (NEPA).
| |
| | |
| ====1.2.1 Safety====
| |
| Review License renewal requirements for power reactors are based on two key principles:
| |
| (1) The regulatory process is adequate to ensure that the licensing bases of all currently operating plants maintain an acceptable level of safety with the possible exceptions of the detrimental aging effects on the functions of certain SSCs, as well as a few other safety-related issues, during the period of extended operation.
| |
| (2) The plant-specific licensing basis must be maintained during the renewal term in the same manner and to the same extent as during the original licensing term.
| |
| In implementing these two principles, 10 CFR 54.4, "Scope," defines the scope of license renewal as including those SSCs that (1) are safety
| |
| -related, (2) whose failure could affect safety-related functions, or (3) are relied on to demonstrate compliance with the NRC's regulations for fire protection, environmental qualification (EQ), pressurized thermal shock (PTS), anticipated transient without scram (ATWS), and station blackout (SBO).
| |
| Pursuant to 10 CFR 54.21(a), a license renewal applicant must review all SSCs within the scope of 10 CFR Part 54 to identify SCs subject to an aging management review (AMR). Those SCs subject to an AMR perform an intended function without moving parts or without change in configuration or properties and are not subject to replacement based on a qualified life or specified time period. Pursuant to 10 CFR 54.21(a), a license renewal applicant must demonstrate that the aging effects will be managed such that the intended function(s) of those Introduction and General Discussion 1-4 SCs will be maintained consistent with the current licensing basis (CLB) for the period of extended operation. However, active equipment is considered to be adequately monitored and maintained by existing programs. In other words, detrimental aging effects that may affect active equipment can be readily identified and corrected through routine surveillance, performance monitoring, and maintenance. Surveillance and maintenance programs for active equipment, as well as other maintenance aspects of plant design and licensing basis, are required throughout the period of extended operation.
| |
| Pursuant to 10 CFR 54.21(d), the LRA is required to include a UFSAR supplement with a summary description of the applicant's programs and activities for managing aging effects and an evaluation of time
| |
| -limited aging analyses (TLAAs) for the period of extended operation.
| |
| License renewal also requires TLAA identification and updating. During the plant design phase, certain assumptions about the length of time the plant can operate are incorporated into design calculations for several plant SSCs. In accordance with 10 CFR 54.21(c)(1), the applicant must either show that these calculations will remain valid for the period of extended operation, project the analyses to the end of the period of extended operation, or demonstrate that the aging effects on these SSCs will be adequately managed for the period of extended operation.
| |
| In 2005, the NRC revised Regulatory Guide (RG) 1.188, "Standard Format and Content for Applications to Renew Nuclear Power Plant Operating Licenses." This RG endorses Nuclear Energy Institute (NEI) 95
| |
| -10, Revision 6, "Industry Guideline for Implementing the Requirements of 10 CFR Part 54
| |
| - The License Renewal Rule," issued in June 2005, which details an acceptable method of implementing 10 CFR Part 54. The staff also used the SRP
| |
| -LR to review the LRA.
| |
| In the LRA, the applicant used the process defined in NUREG
| |
| -1801, Revision 1, "Generic Aging Lessons Learned (GALL) Report," dated September 2005. The GALL Report summarizes staff-approved aging management programs (AMPs) for many SCs subject to an AMR. If an applicant commits to implementing these staff
| |
| -approved AMPs, the time, effort, and resources for LRA review can be greatly reduced, improving the efficiency and effectiveness of the license renewal review process. The GALL Report summarizes the aging management evaluations, programs, and activities credited for managing aging for most of the SCs used throughout the industry. The report is also a quick reference for both applicants and staff reviewers to AMP s and activities that can manage aging adequately during the period of extended operation.
| |
| During the applicant's preparation and submittal of its LRA, the staff was in the process of developing and implementing Revision 2 to the SRP
| |
| -LR and to the GALL Report. The revisions to these two documents were issued in December 2010. As described above, the applicant's LRA was developed to Revision 1 of both the SRP
| |
| -LR and the GALL Report. The staff performed its reviews in accordance with the requirements of 10 CFR Part 54 and the guidance provided in SRP
| |
| -LR, Revision 2, and the GALL Report, Revision 2, both dated December 2010. While this SER is administratively formatted to align with the LRA, using the numbering sequences of the SRP
| |
| -LR and the GALL Report, Revision 1 (such as the numbering of AMR items), the staff reviewed LRA content using the guidance in Revision 2 of the SRP
| |
| -LR and the GALL Report. In places where LRA details differed from Revision 2 of these two documents, the staff issued RAIs to complete its evaluation.
| |
| | |
| Introduction and General Discussion 1-5 1.2.2 Environmental Review Part 51 of 10 CFR contains the NRC's regulations on environmental protection, which implement Section 102(2) of NEPA. In December 1996, the staff revised the environmental protection regulations to facilitate the environmental review for license renewal. The staff prepared the GEIS to document its evaluation of potential environmental impacts associated with nuclear power plant license renewals. For certain types of environmental impacts, the GEIS, as revised, contains generic findings (i.e., Category 1 issues) that apply to all nuclear power plants and are codified in Table B
| |
| -1 of Appendix B, "Environmental Effect of Renewing the Operating License of a Nuclear Power Plant," to Subpart A, "National Environmental Policy Act - Regulations Implementing Section 102(2)," of 10 CFR Part 51. Pursuant to 10 CFR 51.53(c)(3)(i), a license renewal applicant may incorporate these generic findings in its environmental report. Pursuant to 10 CFR 51.53(c)(3)(ii), an environmental report also must include analyses of environmental impacts that must be evaluated on a plant-specific basis (i.e., Category 2 issues).
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| In June 2013, the NRC staff issued a final rule revising 10 CFR Part 51 to update the potential environmental impacts associated with the renewal of an operating license for a nuclear power reactor for an additional 20 years. Revision 1 to the GEIS was issued concurrently with the final rule. The revised GEIS specifically supports the revised list of environmental issues identified in the final rule. Revision 1 to the GEIS and the 2013 final rule reflect lessons learned and knowledge gained during previous license renewal environmental reviews.
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| In accordance with NEPA 1969 and 10 CFR Part 51, the staff reviewed the plant
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| -specific environmental impacts of license renewal, including whether there was new and significant information not considered in the GEIS. As part of its environmental scoping process, the staff held public meetings on August 19, 2010, in Hampton, NH, to identify plant
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| -specific environmental issues. The staff issued the draft site
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| -specific GEIS supplement on August 2011. The staff held another public meeting to discuss the draft site
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| -specific GEIS supplement on September 15, 2011, in Hampton, NH. After considering comments on the draft, the staff published the final site
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| -specific GEIS supplement, Supplement 46, in July 2015.
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| | |
| ===1.3 Principal===
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| Review Matters Part 54 of 10 CFR describes the requirements for renewal of operating licenses for nuclear power plants. The staff's technical review of the LRA was performed in accordance with NRC guidance and 10 CFR Part 54 requirements. Section 54.29, "Standards for Issuance of a Renewed License," of 10 CFR sets forth the license renewal standards. This SER describes the results of the staff's safety review.
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| Pursuant to 10 CFR 54.19(a), the NRC requires a license renewal applicant to submit general information, which the applicant provided in LRA Section 1. The staff reviewed LRA Section 1 and finds that the applicant has submitted the required information.
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| Pursuant to 10 CFR 54.19(b), the NRC requires that the LRA include "conforming changes to the standard indemnity agreement, 10 CFR 140.92, Appendix B, to account for the expiration term of the proposed renewed license." On this issue, the applicant stated the following in the LRA:
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| Introduction and General Discussion 1-6 The current indemnity agreement No. B
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| -106 for Seabrook Station states that the agreement shall terminate at the time of expiration of the license. The indemnity agreement lists NPF
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| -86 as the applicable license number. Should the license number be changed upon issuance of the renewed license, NextEra Energy Seabrook requests that conforming changes be made to the indemnity agreement to include the extended period.
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| The staff intends to maintain the original license number upon issuance of the renewed license, if approved. Therefore, conforming changes to the indemnity agreement need not be made, and the 10 CFR 54.19(b) requirements have been met.
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| Pursuant to 10 CFR 54.21, "Contents of Application
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| - Technical Information," the NRC requires that the LRA contain: (a) an integrated plant assessment, (b) a description of any CLB changes during the staff's review of the LRA, (c) an evaluation of TLAAs, and (d) a UFSAR supplement. LRA Sections 3 and 4 and Appendix B address the license renewal requirements of 10 CF R 54.21(a), (b), and (c). LRA Appendix A satisfies the license renewal requirements of 10 CFR 54.21(d).
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| Pursuant to 10 CFR 54.21(b), the NRC requires that, each year following submission of the LRA and at least 3 months before the scheduled completion of the NRC review, the applicant submit an LRA amendment identifying any CLB changes to the facility that affect the contents of the LRA, including the UFSAR supplement. By letters dated August 25, 2011 (ADAMS Accession No. ML11241A142), September 18, 2012 (ADAMS Accession No. ML12268A171), July 2, 2013 (ADAMS Accession No. ML13189A197), October 21, 2013 (ADAMS Accession No. ML13298A009); October 2, 2014 (ADAMS Accession No. ML14282A023), September 18, 2015 (ADAMS Accession No. ML15271A161), October 7, 2016 (ADAMS Accession No. ML16286A630), October 18, 2017 (ADAMS Accession No. ML17291B221), and May 1, 2018 (ADAMS Accession No. ML18121A403), the applicant submitted LRA updates which summarized the CLB changes that have occurred during the staff's review of the LRA. These submissions satisfy 10 CFR 54.21(b) requirements."
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| Pursuant to 10 CFR 54.22, "Contents of Application
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| - Technical Specifications," the NRC requires that the LRA include changes or additions to the technical specifications (TS) that are necessary to manage aging effects during the period of extended operation. The application provided that an Appendix D for TS changes was not used, thus indicating that no changes to the Seabrook TS are required to support the LRA. This adequately addresses the 10 CFR 54.22 requirement.
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| The staff evaluated the technical information required by 10 CFR 54.21 and 10 CFR 54.22 in accordance with NRC regulations and SRP
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| -LR guidance. SER Sections 2 through 4 document the staff's evaluation of the LRA technical information.
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| As required by 10 CFR 54.25, "Report of the Advisory Committee on Reactor Safeguards
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| [ACRS]," the ACRS will issue a report documenting its evaluation of the staff's LRA review and SER. SER Section 5 is reserved for the ACRS report when it is issued. SER Section 6 documents the findings required by 10 CFR 54.29.
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| | |
| Introduction and General Discussion 1-7 1.4 Interim Staff Guidanc e License renewal is a living program. The staff, industry, and other interested stakeholders gain experience and develop lessons learned with each renewed license. The lessons learned address the staff's performance goals of maintaining safety, improving effectiveness and efficiency, reducing regulatory burden, and increasing public confidence. Interim staff guidance (ISG) is documented for use by the staff, industry, and other interested stakeholders on approaches acceptable to the staff until incorporated into such license renewal guidance documents as the SRP
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| -LR and GALL Report.
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| Table 1.4-1 shows the current set of ISGs, as well as the SER sections in which the staff addresses them.
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| Table 1.4-1. Current Interim Staff Guidance ISG Issue (Approved ISG Number)
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| Purpose SER Section "Aging Management of Stainless Steel Structures and Components in Treated Borated Water," Revision 1 (LR-ISG-2011-01) This LR-ISG clarifies the staff's existing position on aging management in treated borated water environments.
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| SER Section 3.2.2.1 "Aging Management Program for Steam Generators" (LR-ISG-2011-02) This LR-ISG evaluates the suitability of using Rev. 3 of NEI 97
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| -06 for implementing the licensee's steam generator aging management program. SER Section 3.0.3.2.2 "Changes to the Generic Aging Lessons Learned (GALL) Report Revision 2 AMP XI.M41, 'Buried and Underground Piping and Tanks'" (LR
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| -ISG-2011-03) This LR-ISG gives additional guidance on managing the effects of aging on buried and underground piping and tanks. SER Section 3.0.3.3.1 "Updated Aging Management Criteria for Reactor Vessel Internal Components for Pressurized Water Reactors" (LR-ISG-2011-04) This LR-ISG updates the GALL Report, Revision 2, and SRP
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| -LR, Revision 2, to ensure consistency with MRP-227-A for the aging management of age
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| -related degradation for PWR RVI components during the term of a renewed operating license.
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| SER Section 3.0.3.3.5 "Ongoing Review of Operatin g Experience" (LR-ISG-2011-05) This LR-ISG clarifies the staff's existing position in the SRP
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| -LR that acceptable license renewal AMPs should be informed and enhanced when necessary, based on the ongoing review of both plant
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| -specific and industry operating experience.
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| SER Section 3.0.5 "Wall Thinning Due to Erosion Mechanisms" (LR-ISG-2012-01) This LR-ISG gives additional guidance on managing the effects of wall thinning due to erosion mechanisms.
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| SER Section 3.0.3.1.6
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| | |
| Introduction and General Discussion 1-8 "Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation" (LR
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| -ISG-2012-02) This LR-ISG gives guidance on managing the effects of aging of internal surfaces, fire water systems, atmospheric storage tanks, and corrosion under insulation.
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| SER Sections 3.0.3.2.3, 3.0.3.2.8, 3.0.3.2.9, 3.0.3.2.14, 3.0.3.2.15, 3.0.3.2.18, 3.2.2.1.5, 3.2.2.1.6, 3.3.2.1.8, 3.3.2.1.18, 3.3.2.1.19, 3.4.2.1.9, and 3.4.2.2.7 "Aging Management of Loss of Coating or Lining Integrity for Internal Coatings/Linings on In
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| -Scope Piping, Piping Components, Heat Exchangers, and Tanks" (LR-ISG-2013-01) This LR-ISG gives guidance on aging management of internal coatings and linings on in
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| -scope piping, piping components, heat exchangers, and tanks. SER Sections 3.0.3.2.3 and 3.0.3.4.1 "Changes to Buried and Underground Piping and Tank Recommendations" (LR-ISG-2015-01) This LR-ISG will replace aging management program (AMP) XI.M41, "Buried and Underground Piping and Tanks," and its associated UFSAR Summary Description in LR-ISG-2011-03, "Changes to the Generic Aging Lessons Learned (GALL) Report Revision 2 Aging Management Program (AMP)
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| XI.M41, 'Buried and Underground Piping and Tanks.'"
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| SER Section 3.0.3.3.1 ISG Issue (Approved ISG Number)
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| Purpose SER Section "Changes to Aging Management Guidance for Various Steam Generator Components" (LR-ISG-2016-01) This LR-ISG describes changes to aging management program (AMP) XI.M19 "Steam Generator," and the aging management review (AMR) items for steam generator components in NUREG
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| -1801 "Generic Aging Lessons Learned (GALL) Report," Revision 2, and NUREG-1800 "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants" (SRP
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| -LR), Revision 2.
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| SER Section 3.0.3.2.2 1.5 Summary of Closure of Open Items As a result of its review of the LRA, including additional information submitted through July 2018, the staff closed the following open items (OIs) previously identified in the SER with Open Items, dated June 6, 2018. No other OIs remain to be addressed. An item is considered open if, in the staff's judgment, it does not meet all applicable regulatory requirements at the time of the issuance of the SER. A summary of the basis for each closed OI is presented here.
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| Open Item OI 3.0.3.1.9
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| -1 SER Section 3.0.3.1.9
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| - ASME Code Section XI, Subsection IWE Program Due to the applicant's previous failure to maintain the annular space between the containment and containment enclosure buildings in a dewatered state, the staff was concerned that the applicant had not implemented procedures and inspection requirements to keep this area dewatered in the future. Accumulation of water in the annular space can potentially degrade the containment liner plate. The staff's concern was tracked as Open Item OI 3.0.3.1.9
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| -1.
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| Introduction and General Discussion 1-9 By letter dated December 10, 2012, the applicant confirmed that measures have been put in place to maintain the subject area dewatered. In addition, the applicant revised Commitment 52, to reflect ongoing implementation. The staff's concern regarding accumulation of water in the annular space between the containment and containment enclosure building is resolved. Open Item OI 3.0.3.1.9
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| -1 is closed. The staff's resolution and closure of this issue is documented in SER Section 3.0.3.1.9.
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| Open Item OI 3.0.3.2.18
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| -1 SER Section 3.0.3.2.18
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| - Structures Monitoring Program Based on the operating experience related to concrete degradation due to alkali
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| -silica reaction (ASR) discovered in 2010, the staff was concerned that the applicant had not enhanced the Structures Monitoring Program to manage the effects of ASR. This issue was identified as Open Item OI 3.0.3.2.18
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| -1. By letter dated May 18, 2018, the applicant submitted enhancements to the Structures Monitoring Program, revised Commitments 32, 33, and 67, and submitted enhancements to the ASME Section XI, Subsection IWL aging management program, to manage the effects of aging of concrete affected by ASR. The applicant also added two new plant
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| -specific aging management programs, the Alkali
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| -Silica Reaction (ASR) Monitoring Program and the Building Deformation Monitoring Program, which augment the Structures Monitoring and Subsection IWL AMPs to manage the effects of aging of concrete affected by ASR. The applicant also added Commitments 45, 66, 83, and 91 related to these plant
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| -specific AMPs. Based on the staff evaluation of these plant
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| -specific AMPs documented in SER Sections 3.0.3.3.6 and 3.0.3.3.7, the staff's concern regarding the management of the effects of aging in concrete affected by ASR is resolved. Open item OI 3.3.2.18
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| -1 is closed.
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| Open Item OI B.1.4
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| -2 SER Section 3.0.5
| |
| - Operating Experience The applicant did not fully describe how it will use future operating experience to ensure that the AMPs will remain effective for managing the aging effects during the period of extended operation. In addition, some program descriptions contain no such statements and, for these AMPs, it is not clear whether the applicant intends to implement actions to monitor operating experience on an ongoing basis and use it to ensure the continued effectiveness of these AMPs. Further, the LRA does not state whether new AMPs will be developed, as necessary. This issue was identified as Open Item OI B.1.4
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| -2. By letter dated January 20, 2012, the applicant described how its operating experience review activities will ensure the continued effectiveness of the aging management activities. The staff evaluated the applicant's operating experience review activities based on the guidance in Final License Renewal Interim Staff Guidance, LR
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| -ISG-2011-05, "Ongoing Review of Operating Experience," dated March 16, 2012. Based on its review, the staff determined that the applicant's programmatic activities for the ongoing review of operating experience are acceptable because (a) the activities will provide for the systematic review of plan t-specific and industry operating experience concerning age
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| -related degradation and aging management and (b) as a result of these reviews, the applicant will enhance the AMPs or develop new AMPs when necessary to ensure that the effects of aging are adequately Introduction and General Discussion 1-10 managed. Open Item OI B.1.4
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| -2 is closed. The staff's resolution and closure of this issue is documented in SER Section 3.0.5.
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| Open Item OI 3.0.3.1.7
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| -1 SER Section 3.0.3.1.7
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| - Bolting Integrity Program In the reviews of LRAs and operating experience, the NRC staff noted that seal cap enclosures can contain water leakage and therefore use of such enclosures should be accounted for in LRAs to ensure proper aging management.
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| The applicant may have used, or currently uses, seal cap enclosures to contain water leakage. The staff noted that the use of such enclosures may not be accounted for in the LRA. For example, the environment within seal cap enclosures may be submerged, rather than the air environment of the original component design. Also, enclosures may prevent the direct inspections of bolting and component external surfaces within the Bolting Integrity and External Surfaces Monitoring Programs, respectively.
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| The staff lacked sufficient information to complete its evaluation of pressure
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| -retaining bolting and component external surfaces surrounded by seal cap enclosures. Specifically, the LRA did not contain AMR items that address bolting and external surfaces in seal cap enclosure environments, which may be submerged due to ongoing leakage within the enclosure. It was also unclear how components within seal cap enclosures will be age
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| -managed, since direct inspection is not possible. Furthermore, it was unclear to the staff whether seal cap enclosure configurations will be used in the period of extended operation. This issue was identified as Open Item OI 3.0.3.1.7
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| -1. By letter dated June 19, 2012, the applicant provided the additional information to address the staff's concern, including a statement that the single seal cap enclosure in place at Seabrook will be removed no later than December 31, 2014. The staff reviewed and accepted the applicant's response, as documented in SER Section 3.0.3.1.7. The concerns associated with OI 3.0.3.1.7
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| -1 are resolved. By letter dated December 10, 2012, the applicant confirmed that the seal cap enclosure from SI
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| -V-82 was removed and the associated valve was replaced in the fall of 2012, during refuel outage 15. Open Item OI 3.0.3.1.7
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| -1 is closed.
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| Open Item OI 3.2.2.1
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| -1 SER Section 3.2.2.1
| |
| - Treated Borated Water The LRA contains several AMR items that manage stainless steel components exposed to treated borated water for loss of material, cracking, and reduction of heat transfer with the Water Chemistry Program. However, the staff noted that the associated treated borated water environments may not be controlled to less than 5 parts per billion (ppb) dissolved oxygen, and thus, the staff lacked sufficient information to conclude that these components will be adequately managed. This issue was identified as Open Item OI 3.2.2.1
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| -1. In its June 19, 2012, response to RAI 3.2.1.48
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| -1, issued on May 29, 2012, the applicant revised the LRA to add the One
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| -Time Inspection Program to verify the effectiveness of the Water Chemistry Program. The staff finds the applicant's response acceptable because the effectiveness of the Water Chemistry Program will be verified by the applicant to ensure that potential degradation due to aging effects will not lead to loss of intended function during the period of extended operation. Furthermore, the staff finds the applicant's proposal to manage aging effects using the Water Chemistry and One
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| -Time Inspection Programs acceptable Introduction and General Discussion 1-11 because the Water Chemistry Program establishes the plant water chemistry control parameters and their limits to mitigate aging and identifies the actions required if the parameters exceed the limits; the One
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| -Time Inspection Program prescribes appropriate inspection techniques capable of detecting loss of material before loss of intended function, consistent with the revised GALL Report guidance. Open Item OI 3.2.2.1
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| -1 is closed. The staff's resolution and closure of this issue is documented in SER Section 3.2.2.1.
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| Open Item OI 4.2.4
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| -1 SER Section 4.2.4
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| - Pressure-Temperature Limit As a part of a separate licensing action on pressure
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| -temperature (P
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| -T) limits, the applicant requested approval of P
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| -T limits that would extend the operating time of the current P
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| -T limit curves from 20 effective full
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| -power years (EFPY) to 23.7 EFPY, based on an updated neutron fluence evaluation. The revised P
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| -T limits were submitted by letter dated November 17, 2011 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML11329A017) in license amendment request (LAR) 11
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| -06. The staff had concerns related to whether the methodology used to develop the P
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| -T limits in LAR 11
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| -06 was consistent with the requirements in Appendix G, "Fracture Toughness Requirements," to 10 CFR Part 50, "Domestic Licensing of Production and Utilization Facilities." Because the methodology used to develop the P
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| -T limits during the initial operating period is the same as that to be used during the period of extended operation, this information is also pertinent to the LRA review. This issue was identified as Open Item OI 4.2.4
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| -1. On January 9, 2013, the applicant responded to an RAI associated with LAR 11
| |
| -06. This RAI response (ADAMS Accession No. ML13014A624) provided a detailed description of how the P
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| -T limit curves, and the methodology used to develop these curves, considered all reactor pressure vessel (RPV) materials (beltline and nonbeltline) and the lowest service temperature of all ferritic reactor coolant pressure boundary (RCPB) materials, consistent with the requirements of 10 CFR Part 50, Appendix G.
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| On April 15, 2013, the NRC staff approved LAR 11
| |
| -06 and issued Amendment No. 135 to License No. NPF
| |
| -86 to amend the TS P
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| -T limit curves for Seabrook. The staff noted that the nozzle embrittlement calculation for Amendment No. 135 is applicable for the Seabrook period of extended operation. The NRC staff determined that the applicant has adequately demonstrated that the TS P
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| -T limit curves are controlling for the entire RPV. Therefore, the NRC staff finds that the concern related to license renewal Open Item OI 4.2.4
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| -1 is resolved. Open Item OI 4.2.4
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| -1 is closed. The staff's resolution and closure of this issue is documented in SER Section 4.2.4.
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| Subsequently, the applicant submitted LAR 14
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| -04 to revise the P
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| -T limits for 55 EFPY. The NRC staff approved LAR 14
| |
| -04 and issued Amendment No. 151 to License No. NPF
| |
| -86 on November 2, 2015 (ADAMS Accession No. ML15096A255), to amend the TS P
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| -T limit curves for Seabrook.
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| Open Item OI 3.0.3.2.2
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| -1 SER Section 3.0.3.2
| |
| - Steam Generator Tube Integrity Program The staff was concerned with the management of cracking due to primary water stress corrosion cracking (PWSCC) on the primary coolant side of steam generator tube
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| -to-tubesheet welds that are made or cladded with nickel alloy. Also, the staff requested that the applicant Introduction and General Discussion 1-12 provide information regarding its one
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| -time inspection of the steam generator divider plate assembly in its UFSAR supplement. This issue was identified as Open Item OI 3.0.3.2.2
| |
| -1. In its response dated December 10, 2012, the applicant stated that Amendment No. 131 to Facility Operating License No. NPF
| |
| -86 for Seabrook was issued on September 10, 2012. This license amendment provides for the permanent application of steam generator tube alternate repair criteria. These alternate repair criteria allow the licensee to exclude the tube
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| -to-tubesheet welds from the RCPB. The applicant further stated that, since the alternate repair criteria have been permanently applied, no plant
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| -specific AMP or alternate aging management method is required.
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| After reviewing the applicant's response to RAI B.2.1.10
| |
| -1, the staff finds the applicant's response acceptable because the NRC has approved the alternate repair criteria (current license amendment) that exclude the tube
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| -to-tubesheet welds from the RCPB on a permanent basis, including for the period of extended operation. Therefore, no plant
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| -specific AMP or alternate aging management method is required. The staff's concern described in RAI B.2.1.10-1 and the related RAI B.2.1.10
| |
| -2 is resolved. Open Item OI 3.0.3.2.2
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| -1 is closed. The staff's resolution and closure of this issue is documented in SER Section 3.0.3.2.
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| | |
| ===1.6 Summary===
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| of Confirmatory Items As a result of its review of the LRA, including additional information submitted through July 2018 the staff determines that no confirmatory items exist that would require a formal response from the applicant.
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| | |
| ===1.7 Summary===
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| of Proposed License Conditions Following the staff's review of the LRA, including subsequent information and clarifications from the applicant, the staff identified the following license conditions.
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| License Condition No. 1:
| |
| The information in the UFSAR supplement submitted pursuant to 10 CFR 54.21(d), as revised during the license renewal application review process, and licensee commitments as listed in Appendix A to the "Safety Evaluation Report Related to the License Renewal of Seabrook Station, "are collectively the "License Renewal UFSAR Supplement." This supplement is henceforth part of the UFSAR which will be updated in accordance with 10 CFR 50.71(e). As such, the licensee may make changes to the programs, activities, and commitments described in the UFSAR supplement provided the licensee evaluates such changes pursuant to the criteria set forth in 10 CFR 50.59, "Changes, tests, and experiments," and otherwise complies with the requirements in that section.
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| License Condition No.2:
| |
| The License Renewal UFSAR Supplement, as updated by license condition [1] above, describes certain programs to be implemented and activities to be completed before the period of extended operation, as follows:
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| (a) The licensee shall implement those new programs and enhancements to existing programs no later than 6 months prior to the period of extended operation [PEO].
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| | |
| Introduction and General Discussion 1-13 (b) The licensee shall complete those activities by the 6
| |
| -month date before the PEO or the end of the last refueling outage prior to the PEO, whichever occurs later.
| |
| The licensee shall notify the NRC in writing within 30 days after having accomplished item (a) above and include the status of those activities that have been or remain to be completed in item (b) above.
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| | |
| 2-1 SECTION 2 STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW
| |
| | |
| ===2.1 Scoping===
| |
| and Screening Methodology
| |
| | |
| ====2.1.1 Introduction====
| |
| | |
| Title 10, Section 54.21, "Contents of Application
| |
| -Technical Information," of the Code of Federal Regulations (10 CFR 54.21) requires each license renewal application (LRA) to include an integrated plant assessment (IPA). The IPA must for those systems, structures, and components (SSCs) within the scope of license renewal, as delineated in 10 CFR 54.4, "Scope," identify and list those structures and components (SCs) subject to an aging management review (AMR).
| |
| LRA Section 2.1, "Scoping and Screening Methodology," describes the scoping and screening methodology used to identify the SSCs at the Seabrook Station, Unit No. 1 (Seabrook) within the scope of license renewal and the SCs subject to an AMR. The staff reviewed the scoping and screening methodology of NextEra Energy Seabrook, LLC (NextEra or the applicant), to determine if it meets the scoping requirements of 10 CFR 54.4(a) and the screening requirements of 10 CFR 54.21.
| |
| In developing the scoping and screening methodology for the LRA, the applicant stated that it considered the following:
| |
| * 10 CFR Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants" (the Rule)
| |
| * Statements of Consideration for the Rule (60 Federal Register (FR) 22461)
| |
| * guidance of Nuclear Energy Institute (NEI) 95-10, Revision 6, "Industry Guideline for Implementing the Requirements of 10 CFR Part 54
| |
| -The License Renewal Rule," dated June 2005 (NEI 95
| |
| -10)
| |
| * correspondence between the U.S. Nuclear Regulatory Commission (NRC), other applicants, and NEI
| |
| | |
| ====2.1.2 Summary====
| |
| of Technical Information in the Application In LRA Sections 2 and 3, the applicant provided the technical information required by 10 CFR 54.4 and 10 CFR 54.21(a). This safety evaluation report (SER) contains sections entitled "Summary of Technical Information in the Application," which provide information taken directly from the LRA.
| |
| In LRA Section 2.1, the applicant described the process used to identify the SSCs that meet the license renewal scoping criteria under 10 CFR 54.4(a) and the process used to identify the SCs that are subject to an AMR, as required by 10 CFR 54.21(a)(1). The applicant provided Structures and Components Subject to Aging Management Review
| |
| * 2-2 the results of the process used for identifying the SCs subject to an AMR in the following LRA sections:
| |
| Section 2.2, "Plant Level Scoping Results"
| |
| * Section 2.3, "Scoping and Screening Results: Mechanical"
| |
| * Section 2.4, "Scoping and Screening Results: Structures and Structural Components" Section 2.5, "Scoping and Screening Results: Electrical and Instrumentation and Controls (I&C) Systems/Commodity Groups" In LRA Section 3, "Aging Management Review Results," the applicant described its aging management results as follows:
| |
| * Section 3.1, "Aging Management of Reactor Vessel, Internals, and Reactor Coolant System"
| |
| * Section 3.2, "Aging Management of Engineered Safety Features"
| |
| * Section 3.3, "Aging Management of Auxiliary Systems"
| |
| * Section 3.4, "Aging Management of Steam and Power Conversion Systems"
| |
| * Section 3.5, "Aging Management of Systems, Structures, and Component Supports" Section 3.6, "Aging Management of Electrical and Instrumentation and Controls" In LRA Section 4, "Time
| |
| -Limited Aging Analyses," the applicant provided its evaluation of time
| |
| -limited aging analyses (TLAAs).
| |
| | |
| ====2.1.3 Scoping====
| |
| and Screening Program Review The staff evaluated the LRA scoping and screening methodology in accordance with the guidance contained in NUREG
| |
| -1800, Revision 2, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants" (SRP
| |
| -LR), Section 2.1, "Scoping and Screening Methodology." The following regulations form the basis for the acceptance criteria for the scoping and screening methodology review:
| |
| * 10 CFR 54.4(a), as it relates to the identification of plant SSCs within the scope of the Rule
| |
| * 10 CFR 54.4(b), as it relates to the identification of the intended functions of SSCs within the scope of the Rule
| |
| * 10 CFR 54.21(a)(1) and 10 CFR 54.21(a)(2), as they relate to the methods used by the applicant to identify plant SCs subject to an AMR As part of the review of the applicant's scoping and screening methodology, the staff reviewed the activities described in the following sections of the LRA using the guidance contained in the SRP-LR:
| |
| Structures and Components Subject to Aging Management Review 2-3
| |
| * Section 2.1, to ensure that the applicant described a process for identifying SCs that are within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)
| |
| * Section 2.2, to ensure that the applicant described a process for determining the SCs that are subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1) and 10 CFR 54.21(a)(2)
| |
| In addition, the staff conducted a scoping and screening methodology audit at Seabrook
| |
| - located in Seabrook Township, Rockingham County, NH, on the western shore of Hampton Harbor, 2 miles (mi) west of the Atlantic Ocean
| |
| -from September 20
| |
| -23, 2010. The audit focused on ensuring that the applicant had developed and implemented adequate guidance to conduct the scoping and screening of SSCs in accordance with the methodologies described in the LRA and the requirements of the Rule. The staff reviewed the implementation of the project-level guidelines and topical reports describing the applicant's scoping and screening methodology. The staff conducted detailed discussions with the applicant on the implementation and control of the license renewal program and reviewed the administrative control documentation used by the applicant during the scoping and screening process, the quality practices used by the applicant to develop the LRA, and the training and qualification of the LRA development team.
| |
| The staff evaluated the quality attributes of the applicant's aging management program (AMP) activities described in Appendix A, "Final Safety Analysis Report Supplement," and Appendix B, "Aging Management Programs," of the LRA. On a sampling basis, the staff performed a system review of the diesel generator, plant floor drain system (DF), roof drain system, service water system, spent fuel pool system, and feedwater system, including a review of the scoping and screening results reports and supporting design documentation used to develop the reports. The purpose of the staff's review was to ensure that the applicant had appropriately implemented the methodology outlined in the administrative controls and to verify that the results are consistent with the current licensing basis (CLB) documentation.
| |
| 2.1.3.1 Implementation Procedures and Documentation Sources for Scoping and Screening The staff reviewed the applicant's scoping and screening implementing procedures, as documented in the Scoping and Screening Methodology and Audit Summary, dated February 4, 2011 (Agencywide Documents and Access Management System (ADAMS) Accession No. ML110270026), to verify that the process used to identify SCs subject to an AMR was consistent with the SRP
| |
| -LR. Additionally, the staff reviewed the scope of CLB documentation sources and the process used by the applicant to ensure that applicant's commitments, as documented in the CLB and relative to the requirements of 10 CFR 54.4 and 10 CFR 54.21, were appropriately considered and that the applicant adequately implemented its procedural guidance during the scoping and screening process.
| |
| 2.1.3.1.1 Summary of Technical Information in the Application In LRA Section 2.1, the applicant addressed the following information sources for the license renewal scoping and screening process:
| |
| * updated final safety analysis report (UFSAR)
| |
| | |
| Structures and Components Subject to Aging Management Review
| |
| * 2-4
| |
| * harsh environment equipment list
| |
| * Maintenance Rule (MRule) database
| |
| * design basis documents (DBDs)
| |
| * piping and instrumentation diagrams (P&IDs)
| |
| * electrical schematics
| |
| * station blackout (SBO) evaluation component database
| |
| * license renewal technical reports 2.1.3.1.2 Staff Evaluation Scoping and Screening Implementing Procedures. The staff reviewed the applicant's scoping and screening methodology implementing procedures, including license renewal guidelines, documents, and reports, as documented in the audit report, to ensure the guidance is consistent with the requirements of the Rule, the SRP
| |
| -LR, and Regulatory Guide (RG) 1.188, "Standard Format and Content for Applications to Renew Nuclear Plant Operating Licenses," Revision 1, dated September 2005, which endorses the use of NEI 95
| |
| -10. The staff finds that the overall process used to implement the 10 CFR Part 54 requirements described in the implementing procedures and AMRs is consistent with the Rule, the SRP
| |
| -LR, and industry guidance.
| |
| The applicant's implementing procedures contain guidance for determining plant SSCs within the scope of the Rule and for determining which SCs within the scope of license renewal are subject to an AMR. During the review of the implementing procedures, the staff focused on the consistency of the detailed procedural guidance with information in the LRA, including the implementation of staff positions documented in the SRP
| |
| -LR, and the information in the applicant's February 3, 2011 (ADAMS Accession No. ML110380081), response to the staff's January 5, 2011 (ADAMS Accession No. ML103420583), request for additional information (RAI). After reviewing the LRA, supporting documentation and the applicant's RAI responses, the staff determined that the scoping and screening methodology instructions are consistent with the methodology description provided in LRA Section 2.1. The applicant's methodology is sufficiently detailed to provide concise guidance on the scoping and screening implementation process to be followed during the LRA activities.
| |
| Sources of CLB Information. The staff reviewed the scope and depth of the applicant's CLB review to verify that the methodology is sufficiently comprehensive to identify SSCs within the scope of license renewal, as well as SCs requiring an AMR. Pursuant to 10 CFR 54.3(a), the CLB is the set of NRC requirements applicable to a specific plant and a licensee's written commitments for ensuring compliance with, and operation within, applicable NRC requirements and the plant
| |
| -specific design basis that are docketed and in effect. The CLB includes applicable NRC regulations, orders, license conditions, exemptions, technical specifications, and design
| |
| -basis information (documented in the most recent UFSAR). The CLB also includes licensee commitments remaining in effect that were made in docketed licensing correspondence, such as licensee responses to NRC bulletins, generic letters, and Structures and Components Subject to Aging Management Review 2-5 enforcement actions, as well as licensee commitments documented in NRC safety evaluations (SEs) or licensee event reports.
| |
| During the audit, the staff reviewed pertinent information sources used by the applicant, including the UFSAR, design
| |
| -basis information, and license renewal drawings. In addition, the applicant's license renewal process identified additional sources of plant information pertinent to the scoping and screening process, including the license renewal database; controlled drawings; and technical correspondence, analyses, and reports. In addition, the applicant had collected UFSAR, design
| |
| -basis information, drawings, and other controlled information, applicable to specific systems, in documents referred to as "Design Basis Documents." The staff confirmed that the applicant's detailed license renewal program guidelines specified the use of the CLB source information in developing scoping evaluations.
| |
| The license renewal database, UFSAR, design
| |
| -basis information, and plant drawings were the applicant's primary repository for system identification and component safety classification information. During the audit, the staff reviewed the applicant's administrative controls for the license renewal database, design
| |
| -basis information, and other information sources used to verify system information. These controls are described, and implementation is governed, by plant administrative procedures. Based on a review of the administrative controls, and a sample of the system classification information contained in the applicable Seabrook documentation, the NRC staff concludes that the applicant has established adequate measures to control the integrity and reliability of Seabrook system identification and safety classification data.
| |
| Therefore, the staff concludes that the information sources used by the applicant during the scoping and screening process provided a sufficiently controlled source of system and component data to support scoping and screening evaluations. During the staff's review of the applicant's CLB evaluation process, the applicant explained the incorporation of updates to the CLB and the process used to ensure those updates are adequately incorporated into the license renewal database and license renewal documents.
| |
| The staff determined that LRA Section 2.1 provided a description of the CLB and related documents used during the scoping and screening process that is consistent with the guidance contained in the SRP
| |
| -LR. In addition, the staff reviewed the implementing procedures and results reports used to support identification of SSCs that the applicant relied on to demonstrate compliance with the safety
| |
| -related criteria, nonsafety
| |
| -related criteria, and the regulated events criteria pursuant to 10 CFR 54.4(a). The applicant's license renewal program guidelines provided a listing of documents used to support scoping and screening evaluations. The staff finds these design documentation sources to be useful for ensuring that the initial scope of SSCs identified by the applicant was consistent with the plant's CLB.
| |
| 2.1.3.1.3 Conclusion On the basis of its review of LRA Section 2.1, the detailed scoping and screening implementing procedures, and the results from the scoping and screening audit, the staff concludes that the applicant's scoping and screening methodology considers CLB information in a manner consistent with the Rule, the SRP
| |
| -LR, and NEI 95
| |
| -10 guidance and, therefore, is acceptable.
| |
| | |
| Structures and Components Subject to Aging Management Review
| |
| * 2-6 2.1.3.2 Quality Controls Applied to LRA Development 2.1.3.2.1 Staff Evaluation The staff reviewed the quality controls used by the applicant to ensure that scoping and screening methodologies used to develop the LRA were adequately implemented. The applicant used the following quality control processes during the LRA development:
| |
| * using corporate and industry license renewal experience to guide the LRA development developing the LRA and performing associated activities using qualified and experienced personnel and assigning document reviewers based on subject matter expertise
| |
| * developing the LRA following NRC endorsed guidance, applicable industry standards, and Seabrook instructions and guidelines
| |
| * validating the LRA content with source documents by license renewal project leads
| |
| * reviewing the LRA using selected industry peers, the Seabrook Operations Review Committee, and site licensing department
| |
| * using a controlled and validated license renewal database for scoping and screening
| |
| * performing formal surveillance of LRA development activities by the Seabrook Nuclear Oversight Department
| |
| * using the Corrective Actions Program to report discrepancies in the plant equipment database and drawings During the scoping and screening methodology audit, the staff reviewed the applicant's written procedures and quality control records and determined that the applicant had developed adequate procedures to control the LRA development and assess the results of the activities.
| |
| 2.1.3.2.2 Conclusion On the basis of its review of pertinent LRA development procedures and guidance, discussion with the applicant's license renewal staff, and review of the applicant's documentation of the activities performed to assess the quality of the LRA, the staff concludes that the applicant's quality assurance activities provide assurance that LRA development activities were performed in accordance with the applicant's license renewal program requirements.
| |
| 2.1.3.3 Training 2.1.3.3.1 Staff Evaluation The staff reviewed the applicant's training process to ensure the guidelines and methodology for the scoping and screening activities were applied in a consistent and appropriate manner. As outlined in its implementing procedures, the applicant requires training for personnel participating in the development of the LRA. The activities conducted by the applicant included the following:
| |
| | |
| Structures and Components Subject to Aging Management Review 2-7
| |
| * training and qualification of personnel preparing, verifying, and approving license renewal documents in accordance with documented instructions
| |
| * assigning experienced plant personnel augmented with contracted personnel with license renewal experience to the License Renewal Project Team
| |
| * using orientation, computer
| |
| -based training, activity performance, and observation to accomplish training During the scoping and screening methodology audit, the staff reviewed the applicant's written procedures and, on a sampling basis, reviewed completed qualification and training records and completed checklists for a sample of the applicant's license renewal personnel. The staff determined that the applicant developed and implemented adequate procedures to control the training of personnel performing LRA activities.
| |
| 2.1.3.3.2 Conclusion On the basis of discussions with the applicant's license renewal project personnel responsible for the scoping and screening process and its review of selected documentation in support of the process, the staff concludes that the applicant's personnel were adequately trained and qualified to implement the scoping and screening methodology described in the applicant's implementing procedures and the LRA.
| |
| 2.1.3.4 Scoping and Screening Program Review Conclusion On the basis of a review of information provided in LRA Section 2.1, a review of the applicant's scoping and screening implementing procedures, discussions with the applicant's license renewal personnel, review of the quality controls applied to the LRA development, training of personnel participating in the LRA development, and the results from the scoping and screening methodology audit, the staff concludes that the applicant's Scoping and Screening Program is consistent with the SRP
| |
| -LR and the requirements of 10 CFR Part 54 and, therefore, is acceptable.
| |
| | |
| ====2.1.4 Plant====
| |
| Systems, Structures, and Components Scoping Methodology LRA Section 2.1 described the applicant's methodology used to scope SSCs pursuant to the requirements of 10 CFR 54.4(a). The LRA states that the scoping process examined all SSCs with respect to license renewal. According to the LRA, SSCs were evaluated against criteria provided in 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), and 10 CFR 54.4(a)(3) to determine if the item should be considered within the scope of license renewal. The LRA states that the scoping process identified the following SSCs:
| |
| * SSCs that are safety
| |
| -related and perform or support an intended function for responding to a design
| |
| -basis event (DBE)
| |
| * SSCs that are nonsafety
| |
| -related but their failure could prevent satisfactory accomplishment of a safety
| |
| -related function
| |
| * SSCs that support a specific requirement for one of the five regulated events applicable to license renewal LRA Section 2.1 stated that the scoping methodology used at Seabrook is consistent with 10 CFR Part 54 and with the industry guidance contained in NEI 95
| |
| -10.
| |
| Structures and Components Subject to Aging Management Review
| |
| * 2-8 2.1.4.1 Application of the Scoping Criteria in 10 CFR 54.4(a)(1) 2.1.4.1.1 Summary of Technical Information in the Application LRA Section 2.1.2.1, "10 CFR 54.4(a)(1)
| |
| -Safety-Related SSCs," states, in part:
| |
| Systems, structures and components that perform safety functions as defined in 10 CFR 54.4(a)(1) are within the scope of license renewal. Safety
| |
| -related SSCs are uniquely identified at Seabrook Station. The definition of Safety Related is consistent with the definition in 10 CFR 54.4, as follows:
| |
| | |
| Structures and Components Subject to Aging Management Review 2-9
| |
| * SSCs and related activities relied upon to remain functional during and following design-basis events [DBEs] to ensure:
| |
| * The integrity of the reactor coolant boundary,
| |
| * The capability to shut down the reactor and maintain it in a safe shutdown condition,
| |
| * The capability to prevent or mitigate the consequences of accidents that could result in potential offsite exposures comparable to §50.34(a)(1), * §50.67, or §100.11 of 10 CFR [Part] 50, as applicable. Seabrook Station has implemented Alternate Source Term (AST) with NRC approval.
| |
| * Therefore, §50.67 guidelines are applicable to Seabrook Station. (AST was not adopted for the EQ [environmental qualification], however, the existing conditions are bounding.)
| |
| Components are classified as Safety Class 1, Safety Class 2, Safety Class 3, a nd non-nuclear safety (NNS) in accordance with their importance to nuclear safety. This importance, as established by the assigned safety class, is applied in the design, materials, manufacture or fabrication, assembly, erection, construction, and operation. A single system may have components in more than one safety class. The definitions of safety classes listed apply to fluid pressure boundary components and the reactor containment. Supports that have a nuclear safety function are of the same safety class as the components that they support. All Class 1E safety
| |
| -related electrical, instrumentation and controls systems are Safety Class 3.
| |
| The Equipment Database (EDB) was initially used to identify the safety classification of systems, structures and components for license renewal per 10 CFR 54.4(a)(1).
| |
| Seabrook Station P&IDs [piping and instrumentation diagrams], Electrical One Line diagrams, Civil/Architectural drawings and the UFSAR were used to identify components required to support in
| |
| -scope system
| |
| -level and structure
| |
| -level functions. As described in UFSAR section 3.2.2.2, safety class designation boundaries of safety
| |
| -related systems are shown on the P&IDs and described in the respective sections of the UFSAR. Fluid system component safety class designations are listed in UFSAR Table 3.2
| |
| -2. The Heating, Ventilation and Air Conditioning (HVAC) system component safety class designations are listed in UFSAR Table 3.2
| |
| -4. Seabrook Station structures, systems and components important to safety, as well as their foundations and supports, have been designed to withstand the effects of an Operating Basis Earthquake (OBE) and a Safe Shutdown Earthquake (SSE), and are thus designated as seismic Category I.
| |
| 2.1.4.1.2 Staff Evaluation
| |
| | |
| Structures and Components Subject to Aging Management Review 2-10 Pursuant to 10 CFR 54.4(a)(1), the applicant must consider all safety
| |
| -related SSCs relied upon to remain functional during and following DBEs to ensure the following functions:
| |
| * the integrity of the reactor coolant pressure boundary
| |
| * the capability to shut down the reactor and maintain it in a safe shutdown condition
| |
| * the capability to prevent or mitigate the consequences of accidents which could result in potential offsite exposures comparable to those referred to in 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or 10 CFR 100.11 as applicable With regard to identification of DBEs, Section 2.1.3, "Review Procedures," of the SRP
| |
| -LR states, in part:
| |
| The set of [DBEs] as defined in the rule is not limited to Chapter 15 (or equivalent) of the UFSAR. Examples of [DBEs] that may not be described in this chapter include external events, such as floods, storms, earthquakes, tornadoes, or hurricanes, and internal events, such as a high energy line break. Information regarding [DBEs] as defined in 10 CFR 50.49(b)(1) may be found in any chapter of the facility UFSAR, the Commission's regulations, NRC orders, exemptions, or license conditions within the CLB. These sources should also be reviewed to identify [SSCs] that are relied upon to remain functional during and following [DBEs] (as defined in 10 CFR 50.49(b)(1)) to ensure the functions described in 10 CFR 54.4(a)(1).
| |
| During the audit, the applicant stated that it evaluated the types of events listed in NEI 95
| |
| -10 (i.e., anticipated operational occurrences, design
| |
| -basis accidents (DBAs), external events, and natural phenomena) that were applicable to Seabrook. The staff reviewed the applicant's basis documents, which described all design-basis conditions in the CLB and addressed all events defined by 10 CFR 50.49(b)(1) and 10 CFR 54.4(a)(1). The Seabrook UFSAR and basis documents discussed events such as internal and external flooding, tornados, and missiles. The staff concludes that the applicant's evaluation of DBEs was consistent with the SRP-LR. The applicant performed scoping of SSCs for the 10 CFR 54.4(a)(1) criterion in accordance with the license renewal implementing procedures, which provide guidance for the preparation, review, verification, and approval of the scoping evaluations to ensure the adequacy of the results of the scoping process. The staff reviewed the implementing procedures governing the applicant's evaluation of safety
| |
| -related SSCs and sampled the applicant's reports of the scoping results to ensure that the applicant applied the methodology in accordance with the implementing procedures. In addition, the staff discussed the methodology and results with the applicant's personnel who were responsible for these evaluations.
| |
| The staff reviewed the applicant's evaluation of the Rule and CLB definitions pertaining to 10 CFR 54.4(a)(1), and it determined that the Seabrook CLB definition of safety related met the definition of safety related specified in the Rule. The staff reviewed a sample of the license renewal scoping results for the diesel generator, DF, roof drain system, service water system, spent fuel pool system, feedwater system, and turbine building to provide additional assurance that the applicant adequately implemented its scoping methodology with respect to 10 CFR 54.4(a)(1). The staff verified that the applicant developed the scoping results for each of the sampled systems consistently with the methodology, identified the SSCs credited for Structures and Components Subject to Aging Management Review 2-11 performing intended functions, and adequately described the basis for the results, as well as the intended functions. The staff also confirmed that the applicant had identified and used pertinent engineering and licensing information to identify the SSCs required to be within the scope of license renewal in accordance with the 10 CFR 54.4(a)(1) criteria.
| |
| The staff notes that Seismic Category I SSCs are designed to remain functional if the SSE ground motion occurs.
| |
| 2.1.4.1.3 Conclusion On the basis of its review of the LRA, review of systems (on a sampling basis), discussions with the applicant, and review of the applicant's scoping process, the staff concludes that the applicant's methodology for identifying safety
| |
| -related SSCs relied upon to remain functional during and following DBEs is consistent with the SRP
| |
| -LR and 10 CFR 54.4(a)(1) and, therefore, is acceptable.
| |
| 2.1.4.2 Application of the Scoping Criteria in 10 CFR 54.4(a)(2) 2.1.4.2.1 Summary of Technical Information in the Application LRA Section 2.1.2.2, "10 CFR 54.4(a)(2)
| |
| -Non-Safety Related Affecting Safety
| |
| -Related SSCs," states, in part:
| |
| 10 CFR 54.4(a)(2) requires that all non
| |
| -safety related systems, structures and components whose failure could prevent satisfactory accomplishment of any of the functions identified in §54.4(a)(1) be included within the scope of license renewal. These SSCs are classified non
| |
| -nuclear safety (NNS) in the Seabrook Station UFSAR and NNS is used interchangeably with the Non
| |
| -safety related term. The process used at Seabrook Station for identification of Non
| |
| -Safety Affecting Safety (NSAS) related SSCs is consistent with the NEI 95
| |
| -10 "Industry Guideline for Implementing the Requirements of 10 CFR 54
| |
| - The License Renewal Rule," Rev. 6, June 2005. SSCs required by §54.4(a)(2) for Seabrook Station are included in one of the following four categories:
| |
| Current Licensing Basis (CLB) Topics. The Seabrook Station CLB includes a number of topics that identify non
| |
| -safety related SSCs credited for preventive or mitigative functions in support of safe shutdown for special events (e.g., external floods) or whose failure could prevent satisfactory accomplishment of a safety related function (e.g., seismic interactions). The CLB Topics are discussed in Subsection 2.1.2.2.1.
| |
| Non-safety related SSCs directly connected to safety related SSCs are discussed in subsection 2.1.2.2.2.
| |
| Non-safety related SSCs that are not directly connected to safety related SSCs but whose failure could prevent the satisfactory accomplishment of a safety related function due to spatial Structures and Components Subject to Aging Management Review 2-12 proximity. Non
| |
| -Safety Related SSCs in spatial proximity of Safety Related SSCs are discussed in subsection 2.1.2.2.3.
| |
| A non-safety related SSC could provide functional support for a safety related intended function. The non
| |
| -safety related SSC is required to function so that a safety related SSC performs its intended function (e.g., a non
| |
| -safety related system provides cooling to a safety related pump). Non
| |
| -Safety Related SSCs providing functional support for safety related SSCs are discussed in subsection 2.1.2.2.4.
| |
| SSCs required by §54.4(a)(2) were identified by review of the Seabrook Station UFSAR and other CLB documentation. Plant drawings, DBDs, piping analyses, and the plant equipment database were also used. Plant walk downs were performed, as necessary, to confirm the spatial interaction boundaries.
| |
| LRA Section 2.1.2.2.1 states that the Seabrook CLB includes many topics that identify nonsafety-related SSCs credited for preventive or mitigative functions in support of safe shutdown for special events. Those topics include the following:
| |
| High Energy Line Break (HELB)
| |
| At Seabrook Station, the high energy piping systems were identified using the criteria if the service temperature is greater than 200° F [Fahrenheit] or the design pressure is greater than 275 psig [pounds per square inch gauge]. A HELB could affect EQ Equipment in the area of the break by increasing the local temperature and humidity
| |
| -. All high-energy lines identified in UFSAR section 3, Appendix 3I are included as in-scope for license renewal. High energy lines of one
| |
| -inch diameter or smaller pipe size were excluded from the HELB analysis but still remain as a potential source of spray and/or leakage. All of the HELB Analysis pipe segments are located in buildings with Safety Related Equipment and are therefore in the scope of License Renewal.
| |
| Protection from a high energy line break inside of buildings is provided primarily by separation and redundancy. High energy lines are routed to provide maximum protection by using plant structural elements, such as walls, columns, doors, and pipe whip restraints to prevent uncontrolled whipping of the high energy piping. Outside of buildings, protection from a high energy line break (postulated breaks in, or whip loads) is provided by seismic Category I reinforced concrete walls. These components are in
| |
| -scope for license renewal.
| |
| Internal and External Flooding Events Flooding from various internal sources (e.g., pipe breaks) and external sources were evaluated during the design of the plant.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-13 Protection against possible internal flooding from liquid carrying systems, due to pipe rupture or fire protection activities are discussed in [UFSAR Sections 3.6, 9.33, 9.5.1 and 10.4.5.3].
| |
| Internal flooding features are associated with the Equipment and Floor Drainage System, including sumps, sump pumps, tanks, drains, and piping to remove water from potential internal flooding events, and fire protection activities for areas containing safety
| |
| -related equipment. These design features are in
| |
| -scope for license renewal.
| |
| Protection against possible internal flooding is discussed in UFSAR Section 3.4 "Water Level (Flood) Design." Internal flood protection components are reinforced concrete walls, and concrete and steel curbs. These components are in-scope for license renewal.
| |
| Protection against possible external flooding is discussed in UFSAR Sections 2.4.5.5 "Protective Structures," and Section 2.5.5 "Stability of Slopes." External flood protection components are stone revetment, sheet pile retaining wall, and vertical seawall. These components are in
| |
| -scope for license renewal.
| |
| Internal and External Missile Hazards Missiles that could be generated from internal sources or external sources such as rotating equipment and tornados were considered in the design of the plant.
| |
| Both preventive (e.g., over speed controls, seismic restraints) and mitigative (e.g., missile barriers) features were installed to ensure safe shutdown as required by the CLB for postulated missile hazards. These design features are in
| |
| -scope for license renewal. Missiles that could be generated from internal or external sources as described in UFSAR Section 3.5 for various building and structures are summarized in UFSAR Table 3.5
| |
| -1. The missile protection feature (missile barriers) are typically included as part of the building structure (reinforced concrete wall, floor or ceiling). All structures and their missile shields and barriers listed on UFSAR Table 3.5-12 are designed to resist internal and external missiles in accordance with the CLB, and are i n-scope for license renewal.
| |
| LRA Section 2.1.2.2.2 states, in part, in relation to nonsafety
| |
| -related directly connected to safety-related SSCs, the following:
| |
| For NNS SSCs directly connected to safety related SSCs, the in
| |
| -scope boundary for license renewal extends into the NNS portion of the piping and supports up to and including the first seismic anchor or an equivalent anchor beyond the safety/non
| |
| -safety interface. An equivalent seismic anchor is a combination of pipe restraints as described in UFSAR Section 3.7 (B) and Figure 3.7 (B)
| |
| - 37. An alternative used to specifically identify a seismic anchor or an equivalent anchor is to:
| |
| Structures and Components Subject to Aging Management Review 2-14
| |
| * Include the NNS piping run to the next large piece of plant equipment (e.g., pump, heat exchanger, tank, etc.). The large piece of equipment must also be included in
| |
| -scope and is subject to aging management for the intended function of being an anchor point for the piping run.
| |
| * Include the NNS piping run to a flexible connection
| |
| - a flexible connection is considered a pipe stress analysis model end point when the flexible connection effectively decouples the piping system (i.e., does not support loads or transfer loads across it to connecting piping).
| |
| * For NNS piping runs such as vent or drain piping that end at open floor drains, include the entire piping in the scope of LR.
| |
| * For NNS piping runs that are connected to safety related (SR) piping at both ends, include the entire run of NNS piping between the SR piping.
| |
| * Include the buried portion of the piping in the scope of [license renewal] up to the point where the buried pipe exits the ground.
| |
| NNS structures attached to or next to Scoping Criteria 1 structures are in
| |
| -scope for license renewal if their failure could prevent a Scoping Criteria 1 SSC from performing its intended function.
| |
| LRA Section 2.1.2.2.3 states, in part, in relation to nonsafety
| |
| -related SSCs with the potential for spatial interaction with safety
| |
| -related SSCs, the following:
| |
| For non-safety related NNS SSCs that are not directly connected to safety related SSCs, or are connected downstream of the first equivalent anchor, the non
| |
| -safety SSCs may be in
| |
| -scope if their failure could prevent the performance of the system safety function for which the safety related SSC is required.
| |
| Two approaches were used to determine if a non
| |
| -safety related SSC in proximity to a safety related SSC is in scope for license renewal: the mitigative and preventive approach. Where it could be demonstrated that safety related SSCs are separated from non
| |
| -safety related SSCs by physical barriers, the mitigative option was used (e.g., Tank Farm rooms TF101 and TF102). The preventive option was used in evaluating the vast majority of structures or systems at Seabrook for potential adverse structural or spatial interactions with Scoping Criterion 1 SSCs.
| |
| If a safety related component was determined to exist within that building, then all the NNS components within that building were included in the scope of LR. In other words, if a building contained a safety related component, then the entire building, not just the room, was included in the scope for NSAS [non
| |
| -safety affecting safety].
| |
| There is one exception to the application of above methodology. NEI 10 section 3.1.1 recognizes that "a system, structure or component may not meet the requirements of §54.4(a)(1) although it is designated as safety related for plant specific reasons. However, the systems, structures and components Structures and Components Subject to Aging Management Review 2-15 would still need to be evaluated for inclusion into the scope of the Rule using the criteria in §54.4(a)(2) and §54.4(a)(3)."
| |
| The Turbine Building contains components associated with the reactor protection and engineered safety features actuation system which have been classified as safety related in the plant equipment database. There are no other safety related SSCs in the Turbine Building. These components do not perform a safety function, as defined in 10 CFR 54.4(a)(1), and are not credited in the Seabrook Station accident analysis. The CLB does not credit operation of these components during or after a seismic event and thus seismic design or qualification is not required. Therefore, there are no components in the Turbine Building that are considered to be in scope for license renewal as defined in 10 CFR 54.4(a)(2).
| |
| The Turbine Building is a non
| |
| -seismic Category I structure (UFSAR 1.2.2.9). The entire Turbine Building is designed against failure due to Tornado Wind and SSE Loads that could affect any seismic Category I structures in the proximity and therefore considered to be in
| |
| -scope for license renewal as defined in 10 CFR 54.4(a)(2) (UFSAR Tables 3.3
| |
| -4 and 3.7(B)
| |
| -22). NNS Conduits, Trays, Junction Boxes, and Lighting Fixtures NNS conduits, cable trays, junction boxes, lighting fixtures may contain or be routed near Scoping Criterion 1 cables or other components. To determine which of these commodities to consider in
| |
| -scope for license renewal, a conservative simplified approach is used. All NNS conduits, trays, junction boxes and lighting fixtures and their supports located within structures housing safety related equipment are in
| |
| -scope for license renewal.
| |
| -. NNS HVAC Ducts and Supports At Seabrook Station, the [NNS] HVAC ducting was evaluated similar to air/gas piping systems utilizing the guidance provided in NEI 95-10 Appendix F. All HVAC duct supports located within structures housing Scoping Criterion 1 components are in
| |
| -scope for license renewal similar to Air/Gas Systems.
| |
| LRA Section 2.1.2.2.4 states, in part, in relation to nonsafety SSCs providing functional support for safety
| |
| -related SSCs, the following:
| |
| The review of the CLB identified a diesel driven pump as a component that supports a safety related intended function. The portable Cooling Tower makeup pump is maintained on the site. It is capable of providing makeup water to the Service Water System (section 2.3.3.37) Cooling Tower basin from the nearby Browns River or Hampton Harbor with several locations accessible by road. This pump is stored in a Seismic Category 1 building, and is used to ensure a 30 day supply of water in the cooling tower basin in the event of design bases event and subsequent seismic event, the Safe Shutdown Earthquake.
| |
| Structures and Components Subject to Aging Management Review 2-16 This diesel driven pump (1
| |
| -SW-P-329) has been included in the scope of license renewal. 2.1.4.2.2 Staff Evaluation Pursuant to 10 CFR 54.4(a)(2), the applicant must consider all nonsafety
| |
| -related SSCs, whose failure could prevent the satisfactory accomplishment of any of the following functions:
| |
| * the integrity of the reactor coolant pressure boundary
| |
| * the capability to shut down the reactor and maintain it in a safe shutdown condition
| |
| * the capability to prevent or mitigate the consequences of accidents which could result in potential offsite exposures comparable to those referred to in 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or 10 CFR 100.11, as applicable RG 1.188, Revision 1, endorses the use of NEI 95
| |
| -10, Revision 6. NEI 95
| |
| -10 discusses the staff's position on 10 CFR 54.4(a)(2) scoping criteria to include nonsafety
| |
| -related SSCs that may have the potential to prevent satisfactory accomplishments of safety
| |
| -related intended functions as follows: consideration of missiles, cranes, flooding, and HELBs; nonsafety
| |
| -related SSCs connected to safety
| |
| -related SSCs; nonsafety
| |
| -related SSCs in proximity to safety
| |
| -related SSCs; and mitigative and preventive options related to nonsafety
| |
| -related and safety
| |
| -related SSCs interactions.
| |
| In addition, the staff's position (as discussed in the SRP
| |
| -LR Section 2.1.3.1.2) is that applicants need not consider hypothetical failures but, rather, should base their evaluation on the plant's CLB, engineering judgment and analyses and relevant operating experience. NEI 95-10 further describes operating experience as all documented plant
| |
| -specific and industrywide experience that can be used to determine the plausibility of a failure. Documentation would include NRC generic communications and event reports, plant
| |
| -specific condition reports, industry reports such as safety operational event reports, and engineering evaluations. The staff reviewed LRA Section 2.1.2.2 in which the applicant described the scoping methodology for nonsafety
| |
| -related SSCs pursuant to 10 CFR 54.4(a)(2). In addition, the staff reviewed the applicant's implementing document and results report, which documented the guidance and corresponding results of the applicant's scoping review pursuant to 10 CFR 54.4(a)(2). The applicant stated that it performed the review in accordance with the guidance contained in NEI 95
| |
| -10, Revision 6, Appendix F.
| |
| Nonsafety-Related SSCs Required to Perform a Function that Supports a Safety
| |
| -Related SSC The staff determined that nonsafety
| |
| -related SSCs required to remain functional to support a safety-related function had been reviewed by the applicant for inclusion within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The staff reviewed the evaluating criteria discussed in LRA Section 2.1.2.2.4 and the applicant's 10 CFR 54.4(a)(2) implementing document. The staff confirmed that the applicant had reviewed the UFSAR, plant drawings, the plant equipment database, and other CLB documents to identify the nonsafety-related systems and structures that function to support a safety
| |
| -related system whose failure could prevent the performance of a safety
| |
| -related intended function. The applicant also considered missiles, overhead handling systems, internal and external flooding, and HELBs. Accordingly, the staff finds that the applicant implemented an acceptable method Structures and Components Subject to Aging Management Review 2-17 for including nonsafety
| |
| -related systems that perform functions that support safety
| |
| -related intended functions within the scope of license renewal, as required by 10 CFR 54.4(a)(2).
| |
| Nonsafety-Related SSCs Directly Connected to Safety
| |
| -Related SSCs The staff confirmed that nonsafety
| |
| -related SSCs, directly connected to SSCs, had been reviewed by the applicant for inclusion within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The staff reviewed the evaluating criteria discussed in LRA Section 2.1.2.2 and the applicant's 10 CFR 54.4(a)(2) implementing document. The applicant reviewed the safety-related to nonsafety
| |
| -related interfaces for each mechanical system in order to identify the nonsafety
| |
| -related components located between the safety
| |
| -to-nonsafety-related interface and license renewal structural boundary.
| |
| The staff determined that in order to identify the nonsafety
| |
| -related SSCs connected to safety
| |
| -related SSCs and required to be structurally sound to maintain the integrity of the safety
| |
| -related SSCs, the applicant used a combination of the following to identify the portion of nonsafety-related piping systems to include within the scope of license renewal:
| |
| * seismic anchors
| |
| * equivalent anchors, as defined in the Seabrook UFSAR
| |
| * bounding conditions described in NEI 95
| |
| -10, Revision 6, Appendix F (base-mounted component, flexible connection, inclusion to the free end of nonsafety
| |
| -related piping, or inclusion of the entire piping run)
| |
| Nonsafety-Related SSCs with the Potential for Spatial Interaction with Safety
| |
| -Related SSCs The staff confirmed that nonsafety
| |
| -related SSCs with the potential for spatial interaction with safety-related SSCs had been reviewed by the applicant for inclusion within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The staff reviewed the evaluating criteria discussed in the LRA Section 2.1.2.2.3 and the applicant's 10 CFR 54.4(a)(2) implementing procedure. The applicant considered physical impacts (pipe whip, jet impingement) harsh environments, flooding, spray, and leakage when evaluating the potential for spatial interactions between nonsafety
| |
| -related systems and safety
| |
| -related SSCs. The staff further confirmed that the applicant used a preventive, spaces approach to identify the portions of nonsafety
| |
| -related systems with the potential for spatial interaction with safety
| |
| -related SSCs. The spaces approach focused on the interaction between nonsafety
| |
| -related and safety
| |
| -related SSCs that are located in the same space, which was defined for the purposes of the review as a structure containing active or passive safety
| |
| -related SSCs.
| |
| LRA Section 2.1.2.2.3 and the applicant's implementing document state that the applicant included mitigative features when considering the impact of nonsafety
| |
| -related SSCs on safety-related SSCs for occurrences discussed in the CLB. The staff reviewed the applicant's CLB information
| |
| -primarily contained in the UFSAR
| |
| -related to missiles, crane load drops, flooding, and HELBs. The staff determined that the applicant also considered the features designed to protect safety
| |
| -related SSCs from the effects of these occurrences through the use of mitigating features such as floor drains and curbs. The staff confirmed that the applicant included the mitigating features within the scope of license renewal, in accordance with 10 CFR 54.4(a)(2).
| |
| | |
| Structures and Components Subject to Aging Management Review 2-18 LRA Section 2.1.2.2.3 and the applicant's implementing document state that the applicant used a preventive approach, which considered the impact of nonsafety
| |
| -related SSCs contained in the same space as safety
| |
| -related SSCs. The staff determined that the applicant evaluated all nonsafety
| |
| -related SSCs containing liquid or steam and located in spaces containing safety
| |
| -related SSCs. The applicant used a spaces approach to identify the nonsafety-related SSCs that were located within the same space as safety
| |
| -related SSCs. As described in the LRA, and for the purpose of the scoping review, a space was defined as a structure containing active or passive safety
| |
| -related SSCs. In addition, the staff determined that, following the identification of the applicable mechanical systems, the applicant identified its corresponding structures for potential spatial interaction, based on a review of the CLB and plant walkdown. Nonsafety
| |
| -related systems and components that contain liquid or steam and are located inside structures that contain safety
| |
| -related SSCs were included within the scope of license renewal, unless it was evaluated and determined not to contain safety
| |
| -related SSCs. The staff also determined that, based on plant
| |
| - and industry
| |
| -operating experience, the applicant excluded the nonsafety
| |
| -related SSCs containing air or gas from the scope of license renewal, with the exception of portions that are attached to safety
| |
| -related SSCs and required for structural support. The staff determined that additional information would be required to complete the review of the applicant's scoping methodology. RAI 2.1
| |
| -1, dated January 5, 2011 (ADAMS Accession No. ML103420583), states that during the scoping and screening methodology audit performed on site from September 20
| |
| -23, 2010, the staff reviewed the LRA and the applicant's 10 CFR 54.4(a) implementing documents. The staff determined that the applicant had identified and evaluated safety
| |
| -related components located in the turbine building and that the applicant had concluded that the nonsafety
| |
| -related SSCs in the proximity of, or attached to, the safety
| |
| -related SSCs were not required to be included within the scope of license renewal. The staff requested that the applicant do the following:
| |
| * identify SSCs located in the turbine building that are classified as safety
| |
| -related in the plant EDB that were not included within the scope of license renewal in accordance with 10 CFR 54.4(a)(1)
| |
| * provide the details of the evaluation and the basis for the conclusion that SSCs, located in the turbine building that are classified as safety
| |
| -related in the plant EDB, do not have an intended function that requires the SSCs to be included within the scope of license renewal in accordance with 10 CFR 54.4(a)(1)
| |
| * provide the details of the evaluation and basis for the conclusion that nonsafety
| |
| -related SSCs, in the proximity of or attached to SSCs located in the turbine building and classified as safety
| |
| -related in the plant EDB, are not required to be included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2)
| |
| The applicant responded to RAI 2.1
| |
| -1 by letter dated February 3, 2011, which states, in part:
| |
| The following components are classified as being safety
| |
| -related and Class IE, are located in the non
| |
| -seismic turbine building and are not included in the scope of license renewal in accordance with 10 CFR 54.4(a)(1).
| |
| * Turbine Impulse Chamber Pressure Transmitters
| |
| * Turbine Steam Stop Valve Position Switches
| |
| * Turbine Steam Stop Valve Fluid Pressure Switches
| |
| * Turbine Steam Dump Valve Air Supply Solenoid Valves
| |
| | |
| Structures and Components Subject to Aging Management Review 2-19
| |
| * Feedwater Flow Control and Bypass Valve Position Switches
| |
| * Feedwater Flow Control and Bypass Valve Solenoid Valves The applicant further stated in the February 3, 2011, letter, that the above components were evaluated and the basis for the conclusion that SSCs located in the turbine building that are classified as safety
| |
| -related in the plant EDB do not have an intended function that requires these SSCs to be included within the scope of license renewal in accordance with 10 CFR 54.4(a)(1) is documented as follows.
| |
| The Turbine Impulse Chamber Pressure Transmitters inputs to the SSPS [Solid State Protection System] at Seabrook are designed such that the failure of these transmitters will not prevent actuation of the SSPS. They are designed as safety related so that they cannot prevent the SSPS from functioning. They are inputs to the Reactor Protection System and to the ATWS [anticipated transient without scram] Mitigating system and are not credited in the Seabrook accident analysis.
| |
| -. The Turbine Impulse Pressure transmitters cannot prevent satisfactory accomplishment of any of the safety related functions discussed in 10 CFR 54.4(a)(1). Therefore the requirements of 10 CFR 54.4(a)(2) are not applicable.
| |
| [Turbine Steam Stop Valve Position Switches] are classified as safety related, [however] their functioning is strictly anticipatory-. Since these turbine steam stop valve limit and fluid pressure switches perform no safety function, are not credited in the accident analysis and meet Seabrook Station CLB for preventing interactions from propagating back into the RPS [reactor protection system], they cannot prevent satisfactory accomplishment of any of the safety related functions discussed in 10 CFR 54.4(a)(1). Therefore the requirements of 10 CFR 54.4(a)(2) are not applicable.
| |
| -. The Steam Dump System dump valve solenoids are classified as Class IE and safety related. The design criteria applied to the turbine stop valve limit switches and turbine hydraulic pressure sensors was also applied to the steam dump valve solenoids... While these solenoid valves are classified as safety related, UFSAR Section 10.4.4.3, Safety Evaluation states: "The Steam Dump System is not essential to the safe operation of the plant. It is provided for flexibility of operation." -Since these Steam Dump system solenoids perform no safety function, are not credited in the accident analysis and meet Seabrook Station CLB for preventing interactions from propagating back into the RPS, they cannot prevent satisfactory accomplishment of any of the safety related functions discussed in 10 CFR 54.4(a)(1). Therefore the requirements of 10 CFR 54.4(a)(2) are not applicable.
| |
| -.
| |
| Structures and Components Subject to Aging Management Review 2-20 [Feedwater Flow Control and Bypass Valve Position Switches] and circuits do not interface with either the RPS or the ESFAS [engineered safety features actuation system]-. The position switches do not perform a safety function, are not credited for Accident Monitoring, and cannot prevent satisfactory accomplishment of any of the safety
| |
| -related functions discussed in 10 CFR 54.4(a)(1). Therefore the requirements of 10 CFR 54.4(a)(2) are not applicable.
| |
| -. The Feedwater Regulating and Bypass Valves provide backup to the safety related feedwater isolation valves. Although the solenoids for the feedwater Regulating and Bypass valves are classified as safety related and Class IE, the valves themselves are classified as non
| |
| -safety components. These valves are not credited for containment isolation but perform a non
| |
| -safety related backup to the safety related feedwater water isolation function. Since these feedwater regulating and bypass valve solenoids are not credited for containment isolation, are not safety related per NUREG 0138 criteria and meet the Seabrook Station CLB for preventing interactions from propagating back into the ESFAS, they cannot prevent satisfactory accomplishment of any of the safety related function s discussed in 10 CFR 54.4(a)(1).
| |
| However, since these feedwater regulating and bypass valve solenoids are credited as supporting a non
| |
| -safety related backup isolation function for the feedwater isolation valves (closure of the non
| |
| -safety feedwater regulating and bypass valves), the requirements of 10 CFR 54.4(a)(2) are applicable, i.e., the feedwater regulating and bypass valves must operate to support the feedwater isolation function.
| |
| Additionally, the feedwater regulating and bypass valve solenoids are in scope of license renewal as being required to support 10 CFR 54.4(a)(3), Fire Protection. The intended function for Fire Protection is pressure boundary.
| |
| The staff reviewed the applicant's response to RAI 2.1
| |
| -1 and determined that the applicant described the process used to evaluate systems that contained components that were identified as safety
| |
| -related in the plant EDB but that were not included within the scope of license renewal in accordance with 10 CFR 54.4(a)(1). The staff determined that, during the scoping process, the applicant identified components identified as safety
| |
| -related in the plant EDB that were contained in systems that, when evaluated by the applicant, were determined to not have safety
| |
| -related intended functions that meet the criteria of 10 CFR 54.4(a)(1). The staff considered this information, along with information contained in the LRA and scoping implementing procedures, and determined that some components had been conservatively identified as safety
| |
| -related in the plant EDB although CLB information did not indicate that the plant system was required to perform an intended function meeting the criteria in 10 CFR 54.4(a)(1).
| |
| In addition, the staff determined that, during its review, the applicant had determined that the nonsafety-related feedwater and bypass solenoid valves, even though the valves are not credited for containment isolation, do perform a nonsafety
| |
| -related backup to the safety
| |
| -related feedwater water isolation function. The applicant also determined that the feedwater regulating and bypass valves support a 10 CFR 54.4(a)(3) function for fire protection (pressure Structures and Components Subject to Aging Management Review 2-21 boundary). The applicant revised the LRA to include the feedwater and bypass solenoids within the scope of license renewal, in accordance with 10 CFR 54.4(a)(2) and 10 CFR 54.4(a)(3).
| |
| The staff concludes
| |
| -based on a review of the applicant's assessment of components identified as safety
| |
| -related in the plant EDB but whose parent system was not included within the scope of license renewal in accordance with 10 CFR 54.4(a)(1)
| |
| -that the applicant provided an acceptable basis for not including the systems within the scope of license renewal in accordance with 10 CFR 54.4(a)(1). RAI 2.1
| |
| -1 is resolved.
| |
| The staff determined that additional information would be required to complete the review of the applicant's scoping methodology. RAI 2.1
| |
| -2, dated January 5, 2011 (ADAMS Accession No. ML103420583), states that during the scoping and screening methodology audit performed onsite September 20
| |
| -23, 2010, the staff determined that the applicant reviewed nonsafety-related drain lines in the proximity of safety
| |
| -related SSCs and that the applicant concluded that the drain lines were not required to be included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The staff determined that license renewal drawings included a note applicable to drain lines from relief valves that stated, "Lines are not liquid filled so they have no license renewal
| |
| -intended function and are not in scope." The staff requested that the applicant provide the details of its evaluation and basis for its conclusion that nonsafety
| |
| -related drain lines near safety
| |
| -related SSCs will not be fluid
| |
| -filled during a DBE, the failure of which could not prevent satisfactory accomplishment of the function of safety
| |
| -related SSCs and, therefore, are not required to be included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2).
| |
| The applicant responded to RAI 2.1
| |
| -2 by letter dated February 3, 2011 (ADAMS Accession No. ML110380081), which states, in part, the following:
| |
| The tailpipes for the non
| |
| -safety related DF and [hot water heating system] HW relief valves shown in the above listed locations are not liquid filled during normal plant operation and were evaluated in accordance with the guidance provided in NEI 95
| |
| -10, Revision 6, Section 5.2.2.1, "Systems and Components Containing Air/Gas."
| |
| Additionally, the above listed non
| |
| -safety related DF and HW system relief valves are not designed to operate nor lift during a design basis event. Furthermore, as stated in NUREG 1800, Section A.1 (Branch Technical Position RLSP
| |
| -1), the applicable aging effects to be considered for license renewal include those that could result from normal plant operation, including plant/system operating transients and plant shutdown. Specific aging effects from abnormal events need not be postulated for license renewal.
| |
| As stated above, as part of the integrated plant evaluation for license renewal, Seabrook Station determined that the normal internal environment for the downstream piping or tailpipes from the non
| |
| -safety related relief valves is air
| |
| -indoor uncontrolled. This decision was based on the conclusion that the subject relief valves were designed to limit potential over pressurization of the piping system, which is an extremely rare occurrence, if any at all. The valve set
| |
| -points are rarely challenged, and therefore, it is a rare occurrence for a relief valve to Structures and Components Subject to Aging Management Review 2-22 lift. If a relief valve was to relieve and the downstream pipe become wetted, the pipe would dry over time and return to the air
| |
| -indoor uncontrolled normal environment. Additionally, none of these relief valves are being utilized as a pressure control valve and therefore, the normal internal environment for the subject tail pipes is air
| |
| -indoor uncontrolled (non
| |
| -liquid). The staff reviewed the applicant's response to RAI 2.1
| |
| -2. The staff's review determined that the function of a drain line is to contain and pass fluid when required, and the pipe should be included within the scope of license renewal and subject to AMR in accordance with 10 CFR 54.4 (a)(2) for spatial interaction. The staff further determined that following inclusion of the drain lines within the scope of license renewal, the applicant's AMR will allow for the evaluation of material and environment combinations to identify aging effects and the suitability of AMPs. Subsequent to the initial response, the staff held a conference call with the applicant on April 8, 2011, to explain its concerns. By letter dated April 22, 2011 (ADAMS Accession No. ML11115A116), the applicant provided a revised response that states, in part, that "[b]ased on the teleconference held with the NRC on April 8, 2011, the tail pipes for the non
| |
| -safety related relief valves have been added to the scope of license renewal under 10 CFR 54.4(a)(2) for spatial interaction."
| |
| The staff reviewed the applicant's response to RAI 2.1
| |
| -2. The staff determined that the applicant appropriately amended the information in the LRA to include the nonsafety
| |
| -related drain lines within the scope of license renewal, in accordance with 10 CFR 54.4(a)(2). The staff's concern described in RAI 2.1
| |
| -2 is resolved.
| |
| The staff determined that additional information would be required to complete the review of the applicant's scoping methodology. RAI 2.1
| |
| -3, dated January 5, 2011 (ADAMS Accession No. ML103420583), states that during the scoping and screening methodology audit performed onsite September 20
| |
| -23, 2010, the staff reviewed the LRA and the applicant's 10 CFR 54.4(a) implementing documents, relative to nonsafety
| |
| -related sump pumps. The staff noted that the license renewal implementing documents state that nonsafety
| |
| -related sump pumps that are located in a sump are not included within the scope of license renewal if there is a cover over the sump preventing the pump from spatially interacting with safety
| |
| -related equipment. The staff requested that the applicant provide the details of its evaluation and basis for the conclusion that the failure of nonsafety
| |
| -related sump pumps in the proximity safety-related SSCs could not prevent satisfactory accomplishment of the function of safety
| |
| -related SSCs and, therefore, are not required to be included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2).
| |
| The applicant responded to RAI 2.1
| |
| -3 by letter dated February 3, 2011 (ADAMS Accession No. ML110380081), which states, in part, the following:
| |
| The sump pumps that are located in sumps that have a bolted down solid sump cover are not within the scope of license renewal for 10 CFR 54.4(a)(2). In these cases, the mitigative approach was utilized as the bolted down solid plate would prevent liquid spray from components inside the sump. Steel or stainless steel sump cover plates that are fixed in place are considered part of the building structure and age managed under the Structures Monitoring Program, B.2.1.31, as part of the carbon steel or stainless steel commodity grouping.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-23 All sump locations were reviewed to ensure that this approach was applied consistently. This review identified that four sumps did not have a solid sump cover. Therefore, the sump pumps and piping inside these sumps were brought into the scope for license renewal. These sumps are located in the East and West Main Steam and Feedwater Pipe Chases and Intake and Discharge Transition Structures. On LRA drawing PID DFLR20200, sump pumps P
| |
| -51A, P-51B, P-267A, P-267B, P-268A, and P
| |
| -268B and associated piping in the sumps should have been colored Green instead of Black.
| |
| The above listed four pumps are not utilized to mitigate internal flooding events. The nonsafety related sump pumps, piping, and valves that are necessary to mitigate the effects of internal flooding events and fire protection activities in areas containing safety related equipment are in scope of license renewal for 10 CFR.54(a)(2) or 10 CFR.54(a)(3) regardless of the type of sump covers they have. The staff reviewed the applicant's response to RAI 2.1
| |
| -3. The staff's review determined that for nonsafety
| |
| -related sump pumps with permanently attached covers, the applicant had appropriately included the permanently attached sump pump covers as a mitigating feature to prevent spatial interaction, in accordance with 10 CFR 54.4(a)(2). In addition, during its review, the applicant identified four nonsafety
| |
| -related sump pumps that did not have permanently attached covers. In these cases, the applicant revised the LRA to include the sump pump and associated piping within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). Therefore, the staff's concern described in RAI 2.1
| |
| -3 is resolved.
| |
| Based on its review of the LRA, the results of the scoping and screening methodology audit and the applicant's responses to RAIs 2.1
| |
| -1, 2.1-2, and 2.1
| |
| -3, the staff confirmed that fluid
| |
| -filled nonsafety
| |
| -related SSCs, in proximity to safety
| |
| -related SSCs and whose failure could potentially prevent accomplishment of a safety function, were included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2).
| |
| 2.1.4.2.3 Conclusion On the basis of its review of the LRA, review of the applicant's scoping process, discussions with the applicant, and review of the information provided in the response to RAIs 2.1
| |
| -1, 2.1-2, and 2.1-3, the staff concludes that the applicant's methodology for identifying and including nonsafety-related SSCs, that could affect the performance of safety
| |
| -related SSCs, within the scope of license renewal, is consistent with the scoping criteria of 10 CFR 54.4(a)(2) and, therefore, is acceptable.
| |
| 2.1.4.3 Application of the Scoping Criteria in 10 CFR 54.4(a)(3) 2.1.4.3.1 Summary of Technical Information in the Application LRA Section 2.1.2.3, "10 CFR 54.4(a)(3)
| |
| -Regulated Events," states, in part:
| |
| The third scoping category in 10 CFR 54.4 involves SSCs relied upon by licensees to address five regulated events. Specifically, §54.4(a)(3) defines SSCs as in
| |
| -scope for license renewal, if relied on in safety analyses or plant Structures and Components Subject to Aging Management Review 2-24 evaluations to perform a function that demonstrates compliance with one or more of the regulated events:
| |
| * Fire Protection (10 CFR 50.48)
| |
| * Environmental Qualification (10 CFR 50.49)
| |
| * Anticipated Transient Without Scram (10 CFR 50.62)
| |
| * Station Blackout (10 CFR 50.63)
| |
| * Pressurized Thermal Shock (10 CFR 50.61)
| |
| Any SSC that is required to function in order to meet compliance requirements of one or more of these regulations was identified as required by §54.4(a)(3)-.
| |
| Fire Protection Scoping All systems, structures and components relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance with the Commission's regulations for Fire Protection (10 CFR 50.48) were included in the scope of License Renewal in accordance with 10 CFR 54.4(a)(3) requirements. The scope of systems and structures required for compliance with 10 CFR 50.48 are described in UFSAR Appendix A and Appendix R. They include:
| |
| * Systems and structures required to demonstrate safe shutdown capabilities.
| |
| * Systems and structures required for fire detection and suppression needed to support safe shutdown.
| |
| * Systems and structures required to meet commitments made to Appendix A of Branch Technical Position APCSB [Auxiliary and Power Conversion Systems Branch] 9.5-1 with respect to the protection of systems important to safety and prevention of radioactive releases to the environment.
| |
| The License Renewal fire protection technical report documents the results of a detailed review of Seabrook's fire protection program documents that demonstrate compliance with the requirements of 10 CFR 50.48. This document provides a list of systems and structures credited in the plant's fire protection and safe shutdown evaluations. The identified systems and structures are in the scope of License Renewal under 10 CFR 54.4(a)(3) scoping criteria.
| |
| -. Environmental Qualification Scoping The CLB for Seabrook Station's EQ [Environmental Qualification] Program is Title 10, Part 50, Section 49 of the Code of Federal Regulations (10 CFR 50.49).
| |
| This is achieved via conformance to the requirements of NUREG
| |
| -0588, "Interim Structures and Components Subject to Aging Management Review 2-25 Staff Position on Environmental Qualification of Safety
| |
| -Related Electrical Equipment" Category I criteria. Category I criteria incorporates and supplements IEEE [Institute of Electrical and Electronics Engineers] 323
| |
| -1974, "IEEE Standard for Qualifying Class 1E Equipment for Nuclear Power Generating Stations." -. The EQ portion of the license renewal scoping was performed utilizing the Harsh Environment Equipment list. Systems and structures containing equipment within the scope of the EQ Program were identified. The buildings serve to provide shelter, support and protection of EQ equipment.
| |
| Components in the EQ program are evaluated in the EQ TLAA, Section 4.4.
| |
| Anticipated Transients Without Scram Scoping 10 CFR 54.4(a)(3) requires that all systems, components and structures relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance with the Commission's regulations for Anticipated Transients Without Scram (ATWS) (10 CFR 50.62) be included in the scope of License Renewal.
| |
| -. An ATWS Mitigation System (AMS) is installed at Seabrook Station which provides an alternative means for automatically tripping the turbine and actuating Emergency Feedwater (EFW) flow that is independent of the protection system actuations.
| |
| Seabrook Station SSCs used to mitigate an ATWS event have been included in the scope of License Renewal.
| |
| Station Blackout Scoping 10 CFR 54.4(a)(3) requires that all systems, structures and components relied upon in safety analyses or plant evaluations to perform a function that is credited in demonstrating compliance with the Commission's regulations for Station Blackout (10 CFR 50.63) be included in the scope of License Renewal. -. Seabrook Station complies with the requirements of 10 CFR 50.63 as a coping plant. This means that safe shutdown can be maintained using battery backed electrical buses for the four hour coping period. Offsite power and or onsite power will be restored at or before the end of the four hour coping period.
| |
| The SBO Offsite Recovery Path License Renewal Drawing, Figure 2.5
| |
| -1, was created to depict the in
| |
| -scope portion of the off
| |
| -site power system for Station Blackout (SBO). Seabrook Station has chosen two paths for the recovery of off
| |
| -
| |
| Structures and Components Subject to Aging Management Review 2-26 site power in the event of a Station Blackout (SBO). Path 1 is colored green. Path 2 is colored red. Pressurized Thermal Shock Criterion 10 CFR 54.4(a)(3) requires that all SSCs relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance with the commission's regulations for PTS [pressurized thermal shock]
| |
| be included in the scope of License Renewal.
| |
| Pressurized Thermal Shock (PTS) is a condition that could challenge the integrity of the reactor pressure vessel (RPV). Pressurized Thermal Shock (PTS) may occur during a severe transient such as a Loss of Coolant Accident (LOCA) or a steam line break.
| |
| -. The steel reactor vessel beltline shell, including plates, forgings, and welds, were determined to meet the scoping criteria of 10 CFR 54.4 with respect to pressurized thermal shock.
| |
| 2.1.4.3.2 Staff Evaluation The staff reviewed the applicant's approach to identifying SSCs, in accordance with 10 CFR 54.4(a)(3), which are relied on to perform functions that demonstrate compliance with the requirements of the NRC regulations regarding fire protection, EQ, ATWS, PTS, and SBO. As part of this review, the staff did the following:
| |
| * discussed the applicant's methodology
| |
| * reviewed the boundary drawings
| |
| * reviewed license renewal technical reports associated with the five regulated events
| |
| * reviewed the LRA for the development and approach taken to complete the scoping process for these regulated safety systems
| |
| * evaluated SSCs (on a sampling basis) included within the scope of license renewal pursuant to 10 CFR 54.4(a)(3)
| |
| The staff confirmed that the applicant's implementing procedures were used for identifying Seabrook SSCs within the scope of license renewal pursuant to 10 CFR 54.4(a)(3). The applicant evaluated the Seabrook CLB and other source documents to identify SSCs that perform functions addressed in 10 CFR 54.4(a)(3) and included these SSCs within the scope of license renewal, as documented in the specific Seabrook regulated event(s) license renewal technical reports. The staff determined that these technical report results appropriately reference the information sources used for determining the SSCs credited for compliance with the events listed in the specified regulations for the applicable license renewal regulated events. Fire Protection. The staff determined that the applicant's fire protection scoping document identified SSCs in the scope of license renewal required for fire protection. Seabrook used Structures and Components Subject to Aging Management Review 2-27 CLB documents to identify the SSCs within the scope of license renewal for fire protection, primarily the UFSAR, Section 9.5.1, "Fire Protection Systems." The staff reviewed the source documents used by the applicant including the UFSAR and the Seabrook fire protection
| |
| -related design basis documents. The staff reviewed the fire protection scoping and screening report in conjunction with the LRA and the CLB information to validate the methodology for including the appropriate SSCs within the scope of license renewal. The staff determined that the applicant's scoping included SSCs that perform intended functions to meet the requirements of 10 CFR 50.48. Based on its reviews, the staff determined that the applicant's scoping methodology was adequate for including SSCs credited in performing fire protection functions within the scope of license renewal.
| |
| EQ. The staff confirmed that the applicant's EQ scoping and screening report required the inclusion of safety
| |
| -related electrical equipment; nonsafety
| |
| -related electrical equipment whose failure under postulated environmental conditions could prevent satisfactory accomplishments of safety functions of the safety
| |
| -related equipment; and certain post
| |
| -accident monitoring equipment, as defined in 10 CFR 50.49(b)(1), 10 CFR 50.49(b)(2), and 10 CFR 50.49(b)(3). The staff determined that the applicant used the CLB, as described in the Seabrook UFSAR Section 3.11, as well as its EQ DBD to identify SSCs necessary to meet the requirements of 10 CFR 50.49. The Seabrook Harsh Environment Equipment List contains the EQ identifications for specific components. The staff reviewed the LRA, implementing procedures, and the EQ scoping and screening report to verify that the applicant identified SSCs within the scope of license renewal that meet EQ requirements. Based on that review, the staff determined that the applicant's scoping methodology was adequate for identifying EQ SSCs within the scope of license renewal.
| |
| PTS. The staff confirmed that the applicant's PTS scoping and screening report included the applicant's scoping methodology that used Seabrook CLB information to develop the LRA to comply with 10 CFR 50.61, which resulted in the Seabrook reactor vessel beltline components to be within the scope of license renewal pursuant to 10 CFR 54.4(a)(3). The staff reviewed the document "Seabrook Station Reactor Pressure Vessel Fluence Evaluation at 55 EFPY
| |
| [Effective Full Power Years]," which provides the basis for identifying the specific components in-scope for license renewal. The staff determined that the methodology applied was appropriate for identifying SSCs with functions credited for complying with the PTS regulation and within the scope of license renewal. The staff finds that the scoping results included the SSCs that perform intended functions to meet the requirements of 10 CFR 50.61. The staff determined that the applicant's scoping methodology was adequate for including SSCs credited in meeting PTS requirements within the scope of license renewal ATWS. The staff determined that the applicant's ATWS scoping and screening report included the plant systems credited for ATWS mitigation based on review of the Seabrook CLB and the UFSAR, Section 7.6.12, "ATWS Mitigation System," and Section 15.8, "Anticipated Transients Without Scram." The staff reviewed these documents and the LRA in conjunction with the scoping results to confirm the methodology for identifying ATWS SSCs that are within the scope of license renewal. The staff determined that the scoping results included SSCs that perform intended functions meeting 10 CFR 50.62 requirements. The staff determined that the applicant's scoping methodology was adequate for identifying SSCs with functions credited for complying with the ATWS regulation.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-28 SBO. The staff determined that the applicant's SBO scoping and screening report included SSCs from the Seabrook CLB that the applicant identified were associated with coping and safe shutdown of the plant following an SBO event by reviewing UFSAR Section 8.4, "Compliance With 10 CFR 50.63, Loss of All Alternating Current Power (Station Blackout)," and plant procedures. The staff reviewed a sample of these documents and the LRA, in conjunction with the scoping results, to confirm the applicant's methodology. The staff finds that the scoping results included SSCs that perform intended functions meeting 10 CFR 50.63 requirements. The staff determined that the applicant's scoping methodology was adequate for identifying SSCs credited in complying with the SBO regulations within the scope of license renewal. 2.1.4.3.3 Conclusion On the basis of its review of the LRA, review of samples, discussions with the applicant, and review of the implementing procedures and reports, the staff concludes that the applicant's methodology for identifying SSCs relied upon to remain functional during regulated events meets the scoping criteria pursuant to 10 CFR 54.4(a)(3) and, therefore, is acceptable.
| |
| 2.1.4.4 Plant-Level Scoping of Systems and Structures 2.1.4.4.1 Summary of Technical Information in the Application System and Structure Level Scoping. LRA Section 2.1, "Scoping and Screening Methodology," states, in part: "Scoping" was performed to identify the plant systems and structures which perform intended functions as defined in 10 CFR 54.4(a)(1), (a)(2) or (a)(3). Initially, all Seabrook Station SSCs were examined. If any portion of a system or structure met the scoping criteria of 10 CFR 54.4, the system and/or structure was included in
| |
| -scope for License Renewal. For systems and structures determined to be in scope, the intended functions were identified-. All electrical and Instrumentation and Control systems and components are considered in scope.
| |
| "Screening" was performed to identify the components associated with the in
| |
| -scope systems and structures that are subject to aging management review as defined in 10 CFR 54.21. The screening process examined in-scope components and structures to determine those that are passive and long
| |
| -lived. These components and structures were subject to aging management review-.
| |
| Scoping and screening has been performed consistent with the requirements of 10 CFR 54, the Statements of Consideration related to the license renewal rule, and the guidance provided in NEI 95
| |
| -10, "Industry Guidelines for Implementing the Requirements of 10 CFR Part 54
| |
| - The License Renewal Rule, Revision 6."
| |
| LRA Section 2.1.2, "Scoping Methodology," states, in part:
| |
| The scoping methodology utilized by Seabrook Station is consistent with the guidance provided by NEI 95
| |
| -10, Revision 6. Existing plant documentation was used for this review including the Updated Final Safety Analysis Report Structures and Components Subject to Aging Management Review 2-29 (UFSAR), Technical Specifications and licensing correspondence that collectively form the Seabrook Station Current Licensing Basis (CLB). Additional information sources included Design Basis Documents (DBD's), controlled drawings, Equipment Database and the Maintenance Rule Database.
| |
| All Seabrook Station plant systems and structures were reviewed and evaluated against the scoping criteria to determine which met the requirements for inclusion in the scope of license renewal.
| |
| Scoping was initially performed at the system or structure level in accordance with the criteria identified in 10 CFR 54.4(a). System level and structure intended functions were then identified from a review of CLB documentation. Starting at the system level intended functions, scoping boundaries for each system were determined. The results of this effort form the basis for identification of the in
| |
| -scope components.
| |
| Component information was initially transferred from the Seabrook Station Equipment Database (EDB) to the License Renewal Database. The EDB is used to maintain configuration control of component level information at Seabrook Station. As such, quality assurance applied to the EDB software ensures compliance with requirements and/or commitments that are necessary to support both safety related and non
| |
| -nuclear safety component level information.
| |
| -. Equipment that is stored on site for use in response to design basis events is considered to be within the scope of License Renewal. At Seabrook Station, Station Blackout and Appendix R fire scenarios utilize stored equipment to facilitate contingency actions following the event. The stored equipment is confirmed available and in good operating condition by periodic inspection.
| |
| Tools and supplies used to place the stored equipment in service are not in the scope of License Renewal.
| |
| LRA Section 2.1.2 further states, in part:
| |
| Application of all three 10 CRF 54.4 criteria generated a listing of SSCs that were determined to be in
| |
| -scope for license renewal. Not every component of a system supports the system intended functions. Therefore, some components within an in
| |
| -scope system are not in
| |
| -scope for license renewal.
| |
| For the mechanical scoping effort, summary level boundary descriptions were developed and included in Section 2.3. License Renewal drawings/diagrams were also created from plant controlled PID's - to illustrate in
| |
| -scope mechanical systems, structures and components subject to an aging management review (AMR). These AMR boundaries are depicted on color coded license renewal drawings and contain system boundary flags.
| |
| -.
| |
| Structures and Components Subject to Aging Management Review 2-30 For the electrical scoping effort, boundary drawings were not necessary since commodity grouping was used in the scoping process. The SBO Offsite Recovery Path License Renewal Drawing, Figure 2.5
| |
| -1, was created to depict the in-scope portion of the off
| |
| -site power system for Station Blackout (SBO).
| |
| 2.1.4.4.2 Staff Evaluation The staff reviewed the applicant's methodology for performing the scoping of plant SSCs to ensure that it was consistent with 10 CFR 54.4. The methodology used to determine the SSCs within the scope of license renewal was documented in implementing procedures and scoping results reports for systems. The scoping process defined the plant in terms of systems and structures. Specifically, the implementing procedures identified the systems and structures that are subject to 10 CFR 54.4 review, described the processes for capturing the results of the review, and were used to determine if the system or structure performed intended functions consistent with the criteria of 10 CFR 54.4(a). The process was completed for all systems and structures to ensure that the entire plant was addressed.
| |
| The applicant documented the results of the plant
| |
| -level scoping process in accordance with the implementing documents. The results were provided in the systems and structures documents and reports, which contained the following information:
| |
| * a description of the structure or system
| |
| * a listing of functions performed by the system or structure
| |
| * identification of intended functions
| |
| * the 10 CFR 54.4(a) scoping criteria met by the system or structure references
| |
| * the basis for the classification of the system or structure intended functions During the audit, the staff reviewed a sampling of the documents and reports and concluded that the applicant's scoping results contained an appropriate level of detail to document the scoping process.
| |
| 2.1.4.4.3 Conclusion On the basis of its review of the LRA, site guidance documents, and a sampling of system scoping results during the audit, the staff concludes that the applicant's methodology for identifying SSCs within the scope of license renewal, and their intended functions, is consistent with the requirements of 10 CFR 54.4 and, therefore, is acceptable.
| |
| 2.1.4.5 Mechanical Scoping 2.1.4.5.1 Summary of Technical Information in the Application LRA Section 2.1.2, "Scoping Methodology," states, in part, the following with regard to mechanical scoping:
| |
| Mechanical scoping utilized existing Maintenance Rule (MRule) system functions during the License Renewal scoping. These functions were transferred into the License Renewal Database from the MRule database.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-31 In addition to the MRule functions, functions were created in the License Renewal Database to capture the non
| |
| -safety affecting safety (Criterion 2) and the five regulated events (Criterion 3).
| |
| The MRule system functions that were transferred to the License Renewal Database were validated for accuracy using the UFSAR, Technical Specifications, DBDs (including source documents), and other controlled documentation.
| |
| 2.1.4.5.2 Staff Evaluation The staff evaluated LRA Section 2.1.2, and the guidance in the implementing procedures and reports to perform the review of the mechanical scoping process. The project documents and reports provided instructions for identifying the evaluation boundaries.
| |
| The staff reviewed the implementing documents and the CLB documents associated with mechanical system scoping, and it finds that the guidance and CLB source information noted above were acceptable to identify mechanical components and support structures in mechanical systems that are within the scope of license renewal. The staff conducted discussions with the applicant's license renewal project personnel and reviewed documentation pertinent to the scoping process during the scoping and screening methodology audit. The staff assessed whether the applicant appropriately applied the scoping methodology outlined in the LRA and implementing procedures and whether the scoping results were consistent with CLB requirements. The staff determined that the applicant's procedure was consistent with the description provided in the LRA Section 2.1.2 and the guidance contained in the SRP
| |
| -LR, Section 2.1, and was adequately implemented.
| |
| On a sampling basis, the staff reviewed the applicant's scoping and screening reports for the diesel generator, plant floor drains, roof drain system, service water system, spent fuel pool system, feedwater system, and mechanical component types that met the scoping criteria of 10 CFR 54.4. The staff also reviewed the implementing procedures and discussed the methodology and results with the applicant. The staff verified that the applicant identified and used pertinent engineering and licensing information in order to determine that the mechanical component types are required to be within the scope of license renewal. As part of the review process, the staff evaluated each system's intended function, the basis for inclusion of the intended function, and the process used to identify each of the system component types. The staff verified that the applicant identified and highlighted system P&IDs to develop the license renewal boundaries in accordance with the procedural guidance. Additionally, the staff determined that the applicant independently verified the results in accordance with t he governing procedures. The staff confirmed that the applicant had license renewal personnel knowledgeable about the system, and that these personnel performed independent reviews of the marked
| |
| -up drawings to ensure accurate identification of system
| |
| -intended functions. The staff also confirmed that the applicant performed additional cross
| |
| -discipline verification and independent reviews of the resultant highlighted drawings before final approval of the scoping effort. 2.1.4.5.3 Conclusion On the basis of its review of the LRA, scoping implementing procedures, and a sampling of mechanical scoping results, the staff concludes that the applicant's methodology for identifying mechanical SSCs within the scope of license renewal is in accordance with the requirements of 10 CFR 54.4 and, therefore, is acceptable.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-32 2.1.4.6 Structural Scoping 2.1.4.6.1 Summary of Technical Information in the Application LRA Section 2.1.2, "Scoping Methodology," states, in part, the following with regard to civil and structural scoping:
| |
| Civil controlled drawings and the EDB were used to identify buildings, structures and foundations. The buildings were input into the License Renewal Database as individual or grouped license renewal structures.
| |
| Other information sources, such as CLB documentation, were electronically searched using several keywords (e.g., structure, new structure, building modification) to ensure all plant structures were evaluated for license renewal
| |
| -intended functions regardless of their coverage in the plant equipment database.
| |
| 2.1.4.6.2 Staff Evaluation The staff evaluated LRA Section 2.1.2 implementing procedures and guidelines, and scoping and screening reports to perform the review of the structural scoping process. The license renewal procedures and guidelines provided instructions for identifying the evaluation boundaries. The staff reviewed the applicant's approach to identifying structures relied upon to perform the functions described in 10 CFR 54.4(a). As part of this review, the staff discussed the methodology with the applicant, reviewed the documentation developed to support the review, and evaluated the scoping results for a sample of structures that were identified within the scope of license renewal. The staff determined that the applicant had identified and developed a list of plant structures and the structures intended functions through a review of the plant equipment database, UFSAR, drawings, and walkdowns. Each structure the applicant identified was evaluated against the criteria of 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), and 10 CFR 54.4(a)(3).
| |
| The staff reviewed CLB information, drawings, and implementing procedures to verify the adequacy of the methodology for identifying structures meeting the scoping criteria as defined in the Rule. The staff discussed the methodology and results with the applicant. In addition, the staff reviewed, on a sampling basis, the applicant's scoping and screening reports including information contained in the source documentation to verify that the application of the methodology would provide the results documented in the LRA.
| |
| In a specific example, the staff verified that the applicant had identified and used pertinent engineering and licensing information to determine that the nonsafety
| |
| -related turbine building was included within the scope of license renewal based on it housing and supporting safety
| |
| -related components. As part of the review process, the staff evaluated the intended functions identified for the turbine building and the structural components within, the basis for inclusion of the intended function, and the process used to identify each of the component types.
| |
| 2.1.4.6.3 Conclusion On the basis of its review of information in the LRA, scoping implementation procedures, and a sample of structural scoping results, the staff concludes that the applicant's methodology for Structures and Components Subject to Aging Management Review 2-33 identification of the structural SSCs within the scope of license renewal is in accordance with the requirements of 10 CFR 54.4 and, therefore, is acceptable.
| |
| 2.1.4.7 Electrical Component Scoping 2.1.4.7.1 Summary of Technical Information in the Application LRA Section 2.1.2, "Scoping Methodology" states, in part, the following with regard to electrical and I&C scoping:
| |
| All electrical and I&C systems were considered in
| |
| -scope. Electrical and I&C components were organized into commodity groups. The information provided by NEI 95-10 Appendix B and NUREG
| |
| -1800 Table 2.1
| |
| -5, was used as a basis for categorizing electrical and I&C components into commodity groups such as insulated cables and connections, circuit breakers, and switches. Individual components were not identified. The electrical commodity groups identified resulted from a review of plant documents; controlled drawings, the EDB, and interface with the parallel mechanical screening efforts.
| |
| 2.1.4.7.2 Staff Evaluation The staff evaluated LRA Section 2.1.2 and the guidance contained in the implementing procedures and reports to perform the review of the electrical scoping process. The staff reviewed the applicant's approach to identifying electrical and I&C SSCs relied upon to perform the functions described in 10 CFR 54.4(a). The staff reviewed portions of the documentation used by the applicant to perform the electrical scoping process including the UFSAR, CLB documentation, documents, procedures, drawings, specifications, and codes and standards.
| |
| The staff noted that, after the scoping of electrical and I&C components was performed, the in
| |
| -scope electrical components were categorized into electrical component types. Component types include similar electrical and I&C components with common characteristics. Component-level intended functions of the component types were identified (e.g., cable, connections, fuse holders, terminal blocks, connections and insulators, metal enclosed bus, switchyard bus, and connections).
| |
| As part of this review, the staff discussed the methodology with the applicant, reviewed the implementing procedures developed to support the review, and evaluated the scoping results for a sample of SSCs that were identified within the scope of license renewal. The staff determined that the applicant included electrical and I&C components and also electrical and I&C components contained in mechanical or structural systems within the scope of license renewal on a commodity basis.
| |
| 2.1.4.7.3 Conclusion On the basis of its review of information contained in the LRA, scoping implementing procedures, scoping bases documents, and a sample of electrical scoping results, the staff concludes that the applicant's methodology for the scoping of electrical components within the scope of license renewal is in accordance with the requirements of 10 CFR 54.4 and, therefore, is acceptable.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-34 2.1.4.8 Scoping Methodology Conclusion On the basis of its review of the LRA, implementing procedures, and a sampling of scoping results, the staff concludes that the applicant's scoping methodology was consistent with the guidance contained in the SRP
| |
| -LR and identified those SSCs that are within the scope of license renewal in accordance with 10 CFR 54.4(a)(1)
| |
| -10 CFR 54.4(a)(3). The staff concludes that the applicant's methodology is consistent with the requirements of 10 CFR 54.4(a) and, therefore, is acceptable.
| |
| | |
| ====2.1.5 Screening====
| |
| Methodology 2.1.5.1 General Screening Methodology 2.1.5.1.1 Summary of Technical Information in the Application LRA Section 2.1.3, "Screening Methodology," states, in part:
| |
| Structures and components (or component commodity groups) that perform an intended function without moving parts or without a change in configuration or properties are defined as passive for License Renewal.
| |
| Passive structures and components that are not subject to replacement based on a qualified life or specified time period are defined as long
| |
| -lived for License Renewal. The screening process was used to identify the passive, long
| |
| -lived structures and components in the scope of License Renewal and subject to aging management review. The Seabrook Station screening process determines the structures and components subject to aging management review by:
| |
| * Listing the in
| |
| -scope structures and components by component type,
| |
| * Screening component types by using the passive and long lived criteria, and
| |
| * Identifying the intended functions performed by these structures and components by component type.
| |
| NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants," Revision 2, and NEI 95
| |
| -10, Appendix B were used as the basis for the identification of passive structures and components. Most passive structures and components are long
| |
| -lived. In the few cases where a passive component is determined not to be long
| |
| -lived, such determination is documented in the screening evaluation (e.g., solenoid valves that are periodically replaced).
| |
| Intended functions used to define passive structures and components are identified in LRA Table 2.1
| |
| -1. Structures and components may have multiple intended functions (e.g., heat exchanger with heat transfer and pressure boundary-intended functions). Seabrook has considered multiple intended functions where applicable, consistent with the staff guidance provided in Tables 2.1
| |
| -4(a) and (b) of NUREG
| |
| -1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants." If a component did Structures and Components Subject to Aging Management Review 2-35 not have at least one component
| |
| -level intended function, the component was not subject to an aging management review.
| |
| Detailed scoping and screening reports have been prepared which identify all structures and components subject to an aging management review. These reports have been prepared for all systems, structures, or commodity groups (except electrical commodities) in
| |
| -scope for License Renewal.
| |
| Passive, long
| |
| -lived electrical commodities subject to an aging management review were identified using guidance in NEI 95
| |
| -10. The Seabrook Station structures and components subject to aging management review have been identified in accordance with the requirements of 10 CFR 54.21(a)(1).
| |
| 2.1.5.1.2 Staff Evaluation Pursuant to 10 CFR 54.21, each LRA must contain an IPA that identifies those SCs within the scope of license renewal that are subject to an AMR. The IPA must identify components that perform an intended function without moving parts or without a change in configuration or properties (passive), and that are not subject to replacement based on a qualified life or specified time (long
| |
| -lived). In addition, the IPA must include a description and justification of the methodology used to determine the passive and long
| |
| -lived SCs and a demonstration that the effects of aging on those SCs will be adequately managed so that the intended function(s) will be maintained under all design conditions imposed by the plant
| |
| -specific CLB for the period of extended operation.
| |
| The staff reviewed the methodology used by the applicant to identify the mechanical and structural components and electrical commodity groups within the scope of license renewal that should be subject to an AMR. The applicant implemented a process for determining which SCs were subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1). In LRA Section 2.1.3, the applicant discusses these screening activities as they related to the component types and commodity groups within the scope of license renewal.
| |
| The staff determined that the screening process evaluated the component types and commodity groups included within the scope of license renewal to determine which ones were long-lived and passive and, therefore, subject to an AMR. The staff reviewed LRA Section 2.3, "Scoping and Screening Results: Mechanical," LRA Section 2.4, "Scoping and Screening Results: Structures and Structural Components," and LRA Section 2.5, "Scoping and Screening Results: Electrical and Instrumentation and Controls (I&C) Systems/Commodity Groups." These sections of the LRA provided the results of the process used to identify component types and commodity groups subject to an AMR. The staff also reviewed, on a sampling basis, the screening results reports for safety injection (SI) and shutdown cooling, diesel generator fuel oil storage and transfer, auxiliary feedwater, and the turbine building.
| |
| The applicant provided the staff with a detailed discussion of the processes used for each discipline and provided administrative documentation that described the screening methodology. The specific methodology for mechanical, electrical, and structural is discussed in SER Sections 2.1.5.2 through 2.1.5.4.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-36 2.1.5.1.3 Conclusion On the basis of a review of the LRA, the implementing procedures, and a sampling of screening results, the staff concludes that the applicant's screening methodology is consistent with the guidance contained in the SRP
| |
| -LR and is capable of identifying passive, long
| |
| -lived SCs within the scope of license renewal that are subject to an AMR. The staff concludes that the applicant's process for determining which component types and commodity groups are subject to an AMR is consistent with the requirements of 10 CFR 54.21 and, therefore, is acceptable.
| |
| 2.1.5.2 Mechanical Component Screening 2.1.5.2.1 Summary of Technical Information in the Application LRA Section 2.1.3 states, in part, the following with regard to mechanical screening:
| |
| Mechanical components have been screened with the system in which they were scoped. Plant components such as heat exchangers and coolers that have License Renewal
| |
| -intended functions that are unique have been identified at the subcomponent level to ensure all the intended functions and material / environment combinations are considered in the evaluation (e.g., channel head, shell, tubes, and tube sheet).
| |
| 2.1.5.2.2 Staff Evaluation The staff reviewed the mechanical screening methodology discussed and documented in LRA Section 2.1.3, the implementing documents, the scoping and screening reports, and the license renewal drawings. The staff determined that the mechanical system screening process began with the results from the scoping process and that the applicant reviewed each system evaluation boundary as depicted on the P&IDs to identify passive, long
| |
| -lived components. Additionally, the staff determined that the applicant had identified all passive, long-lived components that perform or support an intended function within the system evaluation boundaries and determined those components to be subject to an AMR. The results of the review were documented in the scoping and screening reports, which contain information such as the information sources reviewed and the component intended functions.
| |
| The staff verified that mechanical system evaluation boundaries were established for each system within the scope of license renewal and that the boundaries were determined by mapping the system
| |
| -intended function boundary onto P&IDs. The staff confirmed that the applicant reviewed the components within the system
| |
| -intended function boundary to determine if the component supported the system
| |
| -intended function and that those components that supported the system
| |
| -intended function were reviewed to determine if the component was passive and long
| |
| -lived and, therefore, subject to an AMR.
| |
| During the scoping and screening methodology audit, the staff reviewed selected portions of the UFSAR, plant equipment database, CLB documentation, Seabrook databases and documents, procedures, drawings, specifications, and selected scoping and screening reports. The staff conducted discussions with the applicant's license renewal team and reviewed documentation pertinent to the screening process. The staff also performed a walkdown of portions of the selected systems with plant engineers to verify documentation. The staff Structures and Components Subject to Aging Management Review 2-37 assessed whether the mechanical screening methodology outlined in the LRA and procedures was appropriately implemented and if the scoping results were consistent with CLB requirements. In addition, during the scoping and screening methodology audit, the staff discussed the screening methodology with the applicant and, on a sampling basis, reviewed the applicant's screening reports for the diesel generator, plant floor drains, roof drain system, service water system, spent fuel pool system, and feedwater system to verify proper implementation of the screening process. Based on these audit activities, the staff did not identify any discrepancies between the methodology documented and the implementation results. 2.1.5.2.3 Conclusion On the basis of its review of the LRA, the screening implementation procedures, selected portions of the UFSAR, plant equipment database, CLB documentation, procedures, drawings, specifications and selected scoping and screening reports, and a sampling of screening results, the staff concludes that the applicant's methodology for identification of mechanical components within the scope of license renewal and subject to an AMR is in accordance with the requirements of 10 CFR 54.21(a)(1) and, therefore, is acceptable.
| |
| 2.1.5.3 Structural Component Screening 2.1.5.3.1 Summary of Technical Information in the Application LRA Section 2.1.3 states, in part, the following with regard to civil and structural screening:
| |
| The screening process was applied to in
| |
| -scope buildings and civil structures to identify the structural elements to be evaluated in the aging management reviews. -. The Seabrook Station scoping and screening process used a "spaces" approach in establishing the evaluation boundaries. With few exceptions, the scoping and screening boundary for a building or structure is an entire building or buildings, including the doors, supports, base slabs, foundations, walls, beams, slabs, roofs, penetration seals and structural steel. The various types of structural elements, and materials that make up the buildings were identified and listed.
| |
| The listing of structural elements is facilitated by grouping them into component groups. Structural components/commodities often do not have unique identifiers such as those given to mechanical components. Therefore, identifying structural components as commodities based on materials of construction, their environment and functional applications provided an identification system for aging management reviews.
| |
| A list of structural commodities (example; carbon steel with indoor air includes, but is not limited to: carbon steel decking, embedments, fasteners, grating, other miscellaneous steel such as fire walls made from carbon steel siding, doors, plates, platforms, rails for hoists, and shapes) was developed for each civil/structural evaluation boundary. Structural commodities that perform an Structures and Components Subject to Aging Management Review 2-38 intended function without moving parts and without a change in configuration or properties, and that are not subject to replacement based on a qualified life or specified time period, are subject to aging management review.
| |
| 2.1.5.3.2 Staff Evaluation The staff reviewed the structural screening methodology discussed and documented in LRA Sections 2.1.3, implementing procedures and guidelines, scoping and screening reports, and the license renewal structures drawing. The staff reviewed the applicant's commodity group methodology for identifying structural components that are subject to an AMR, as required in 10 CFR 54.21(a)(1).
| |
| The staff confirmed that the applicant reviewed the structures included within the scope of license renewal and identified the passive, long
| |
| -lived components with component-level intended functions and determined those components to be subject to an AMR. The staff reviewed selected portions of the UFSAR, structure system information, and scoping and screening reports the applicant used to perform the structural scoping and screening. The staff also reviewed screening activities, on a sampling basis, that documented the SCs within the scope of license renewal. The staff conducted detailed discussions with the applicant's license renewal team and reviewed documentation pertinent to the screening process to assess if the screening methodology outlined in the LRA and implementing procedures was appropriately implemented and if the scoping results were consistent with CLB requirements.
| |
| 2.1.5.3.3 Conclusion On the basis of its review of information contained in the LRA, implementing procedures and guidelines, plant equipment database, and a sampling of the structural screening results, the staff concludes that the applicant's methodology for identification of structural components within the scope of license renewal and subject to an AMR is in accordance with the requirements of 10 CFR 54.21(a)(1) and, therefore, is acceptable.
| |
| 2.1.5.4 Electrical Component Screening 2.1.5.4.1 Summary of Technical Information in the Application LRA Section 2.1.3 states the following, in part, with regard to electrical screening:
| |
| Screening of electrical and I&C components used a bounding approach as described in NEI 95
| |
| -10. All Electrical and I&C systems were considered in
| |
| -scope. Electrical and I&C components were assigned to a commodity grouping. The commodity groups subject to an aging management review were identified by applying the criteria of 10 CFR 54.21(a)(1). This method provided the most efficient means for determining the electrical commodity groups subject to an aging management review since many of the electrical components are active.
| |
| The sequence of steps used by Seabrook Station for identification of electrical commodity groups that require an aging management review was as follows: (1) The criteria of 10 CFR 54.21(a)(1)(i) was applied to identify commodity groups that perform their intended functions without moving parts or without Structures and Components Subject to Aging Management Review 2-39 a change in configuration or properties (referred to as "passive" components). These electrical commodity groups were identified utilizing the guidance of NEI 95
| |
| -10. (2) Portions of electrical commodity groups that perform no License Renewal
| |
| -intended functions do not require aging management review and were not considered further (e.g., ground conductors, switchyard components outside of SBO boundary).
| |
| (3) The screening criterion found in 10 CFR 54.21(a)(1)(ii) excludes those commodity groups that are subject to replacement based on a qualified life or specific time period from the requirements of an aging management review. The 10 CFR 54.21(a)(1)(ii) screening criterion was applied to those commodity groups that were not previously eliminated by the application of the 10 CFR 54.21(a)(1)(i) screening criterion or previously eliminated because they do not perform a License Renewal intended function.
| |
| -. (6) The electrical commodities that require an aging management review are passive electrical commodities. The passive commodity groups that are not subject to replacement based on a qualified life or specified time period are subject to an aging management review-.
| |
| 2.1.5.4.2 Staff Evaluation The staff reviewed the applicant's methodology used for electrical component screening in LRA Sections 2.1.3 and 2.5, the applicant's implementing procedures, bases documents, and electrical AMR reports. The staff confirmed that the applicant used the screening process described in these documents, along with the information contained in NEI 95
| |
| -10 Appendix B and the SRP
| |
| -LR, to identify the electrical and I&C components subject to an AMR.
| |
| The staff determined that the applicant identified commodity groups that met the passive criteria in accordance with NEI 95
| |
| -10. In addition, the staff determined that the applicant evaluated the identified, passive commodities to determine if they were subject to replacement based on a qualified life or specified time period (short
| |
| -lived) or not subject to replacement based on a qualified life or specified time period (long
| |
| -lived). The remaining passive, long
| |
| -lived components were determined to be subject to an AMR.
| |
| The staff performed a review to determine if the screening methodology outlined in the LRA and implementing procedures were appropriately implemented and if the scoping results were consistent with CLB requirements. During the scoping and screening methodology audit, the staff reviewed selected screening reports and discussed the reports with the applicant to verify proper implementation of the screening process. Based on these onsite review activities, the staff did not identify any discrepancies between the methodology documented and the implementation results.
| |
| 2.1.5.4.3 Conclusion
| |
| | |
| Structures and Components Subject to Aging Management Review 2-40 On the basis of its review of the LRA the screening implementation procedures, selected portions of the UFSAR, CLB documentation, procedures, drawings, specifications and selected scoping and screening reports, discussion with the applicant, and a sample of the results of the screening methodology, the staff concludes that the applicant's methodology for identification of electrical components within the scope of license renewal and subject to an AMR is in accordance with the requirements of 10 CFR 54.21(a)(1) and, therefore, is acceptable.
| |
| 2.1.5.5 Screening Methodology Conclusion On the basis of its review of the LRA, the screening implementing procedures, discussions with the applicant's staff, and a sample of the screening results, the staff concludes that the applicant's screening methodology is consistent with the guidance contained in the SRP
| |
| -LR and identified those passive, long
| |
| -lived components within the scope of license renewal that are subject to an AMR. The staff concludes that the applicant's methodology is consistent with the requirements of 10 CFR 54.21(a)(1) and, therefore, is acceptable.
| |
| | |
| ====2.1.6 Summary====
| |
| of Evaluation Findings On the basis of its review of the information presented in LRA Section 2.1, the supporting information in the scoping and screening implementing procedures and reports, the information presented during the scoping and screening methodology audit, discussions with the applicant, sample system reviews, and the applicant's responses dated February 3, 2011 (ADAMS Accession No. ML110380081), to the staff's RAIs, the staff concludes that the applicant's scoping and screening methodology is consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff also concludes that the applicant's description and justification of its scoping and screening methodology are adequate to meet the requirements of 10 CFR 54.21(a)(1). From this review, the staff concludes that the applicant's methodology for identifying systems and structures within the scope of license renewal and SCs requiring an AMR is acceptable.
| |
| 2.2 Plant-Level Scoping Results
| |
| | |
| ====2.2.1 Introduction====
| |
| | |
| In LRA Section 2.1, the applicant described the methodology for identifying SSCs within the scope of license renewal. In LRA Section 2.2, the applicant used the scoping methodology to determine which SSCs must be included within the scope of license renewal. The staff reviewed the plant
| |
| -level scoping results to determine if the applicant has properly identified the following:
| |
| * all SSCs relied upon to mitigate DBEs, as required by 10 CFR 54.4(a)(1)
| |
| * all nonsafety
| |
| -related SSCs whose failure could prevent satisfactory accomplishment of any safety
| |
| -related functions, as required by 10 CFR 54.4(a)(2)
| |
| * systems and structures relied on in safety analyses or plant evaluations to perform functions required by regulations referenced in 10 CFR 54.4(a)(3)
| |
| | |
| Structures and Components Subject to Aging Management Review 2-41 2.2.2 Summary of Technical Information in the Application In LRA Table 2.2
| |
| -1, the applicant listed plant mechanical systems, electrical and I&C systems, and structures within the scope of license renewal. Based on the DBEs considered in the plant's CLB, other CLB information relating to nonsafety
| |
| -related systems and structures, and certain regulated events, the applicant identified plant
| |
| -level systems and structures within the scope of license renewal as defined by 10 CFR 54.4.
| |
| | |
| ====2.2.3 Staff====
| |
| Evaluation In LRA Section 2.1, the applicant described its methodology for identifying systems and structures within the scope of license renewal and subject to an AMR. The staff reviewed the scoping and screening methodology, and its evaluation is provided in SER Section 2.1. To verify that the applicant properly implemented its methodology, the staff's review focused on the implementation results shown in LRA Tables 2.2
| |
| -1, "Systems and Structures Within the Scope of License Renewal," and 2.2
| |
| -2, "Systems and Structures Not in the Scope of License Renewal," to confirm that there were no omissions of plant
| |
| -level systems and structures within the scope of license renewal.
| |
| The staff determined whether the applicant properly identified the systems and structures within the scope of license renewal in accordance with 10 CFR 54.4. The staff reviewed selected systems and structures that the applicant did not identify as within the scope of license renewal to determine whether the systems and structures have any intended functions requiring their inclusion within the scope of license renewal. The staff's review of the applicant's implementation was conducted in accordance with the guidance in SRP
| |
| -LR Section 2.2, "Plant
| |
| -Level Scoping Results."
| |
| The staff noted that, in LRA Section 2.3.3.45, the waste process building is indicated as being not in-scope for license renewal. However, in LRA Section 2.4.5, the applicant states that the waste process building is in
| |
| -scope for 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), and 10 CFR 54.4(a)(3), and is included in Table 2.2
| |
| -1. By letter dated January 5, 2011, the staff issued RAI 2.2
| |
| -01 (ADAMS Accession No. ML103420583) and requested that the applicant clarify whether the waste process building is within the scope of license renewal.
| |
| In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant stated that the waste process building is within scope of license renewal and provided a revised LRA Section 2.3.3.45 to indicate that the waste process building is in
| |
| -scope. Based on its review, the staff finds the applicant's response to RAI 2.2
| |
| -01 acceptable because the applicant revised LRA Section 2.3.3.45 to specify that the waste process building is within the scope of license renewal. Therefore, the staff's concern described in RAI 2.2
| |
| -01 is resolved.
| |
| | |
| ====2.2.4 Conclusion====
| |
| | |
| On the basis of its review of LRA Section 2.2, the RAI response, and the UFSAR supporting information to determine whether the applicant failed to identify any systems and structures within the scope of license renewal, the staff concludes that the applicant has appropriately identified the systems and structures within the scope of license renewal, in accordance with 10 CFR 54.4.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-42 2.3 Scoping and Screening Results: Mechanical Systems This section documents the staff's review of the applicant's scoping and screening results for mechanical systems. Specifically, this section describes the following mechanical systems:
| |
| * reactor vessel, internals, and reactor coolant system (RCS)
| |
| * engineered safety features systems
| |
| * auxiliary systems
| |
| * steam and power conversion systems In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, long-lived SCs within the scope of license renewal and subject to an AMR. To verify that the applicant properly implemented its methodology, the staff's review focused on the implementation results. This focus allowed the staff to verify that the applicant identified the mechanical system SCs that met the scoping criteria and were subject to an AMR and that there were no omissions. The staff's evaluation of mechanical systems was performed using the evaluation methodology described in this SER and in the guidance of SRP
| |
| -LR Section 2.3, and it took into account, where applicable, the system functions described in the UFSAR. The objective was to determine whether the applicant identified, in accordance with 10 CFR 54.4, components and supporting structures for mechanical systems that meet the license renewal scoping criteria. Similarly, the staff evaluated the applicant's screening results to verify that all passive, long
| |
| -lived components are subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| In its scoping evaluation, the staff reviewed the LRA, applicable sections of the UFSAR, license renewal boundary drawings, and other licensing basis documents, as appropriate, for each mechanical system within the scope of license renewal. The staff reviewed relevant licensing basis documents for each mechanical system to confirm that the LRA specified all intended functions defined by 10 CFR 54.4(a). The review then focused on identifying any components with intended functions defined by 10 CFR 54.4(a) that the applicant may have omitted from the scope of license renewal.
| |
| After reviewing the scoping results, the staff evaluated the applicant's screening results. For those SCs with intended functions required by 10 CFR 54.4(a), the staff verified the applicant properly screened out SCs that have functions performed with moving parts or a change in configuration or properties or SCs that are subject to replacement after a qualified life or specified time period, as described in 10 CFR 54.21(a)(1). For SCs not meeting either of these criteria, the staff confirmed that the remaining SCs received an AMR, as required by 10 CFR 54.21(a)(1).
| |
| The staff evaluation of the mechanical system scoping and screening results applies to all mechanical systems reviewed.
| |
| Those systems that required RAIs to be generated include an additional staff evaluation, which specifically addresses the applicant's responses to the RAIs.
| |
| | |
| ====2.3.1 Reactor====
| |
| Vessel, Internals, and Reactor Coolant System LRA Section 2.3.1 identifies the reactor vessel, internals, and reactor coolant system SCs subject to an AMR for license renewal.
| |
| The applicant described the supporting SCs of the reactor vessel, internals, and RCS in the following LRA sections:
| |
| | |
| Structures and Components Subject to Aging Management Review 2-43
| |
| * Section 2.3.1.1, "Reactor Coolant System"
| |
| * Section 2.3.1.2, "Reactor Vessel"
| |
| * Section 2.3.1.3, "Reactor Vessel Internals"
| |
| * Section 2.3.1.4, "Steam Generators" The staff's findings on review of LRA Sections 2.3.1.1
| |
| -2.3.1.4 are provided in SER Sections 2.3.1.1
| |
| -2.3.1.4, respectively.
| |
| 2.3.1.1 Reactor Coolant System 2.3.1.1.1 Summary of Technical Information in the Application The reactor coolant (RC) system consists of four heat transfer loops connected in parallel to the reactor pressure vessel. Each loop contains a reactor coolant pump (RCP), a steam generator, and associated piping and valves. In addition, the RC system includes a pressurizer, pressurizer relief tank, pressurizer relief and safety valves, interconnecting piping, and instrumentation necessary for operational control.
| |
| During operation, the RC system transfers the heat generated in the core to the steam generators, where steam is produced to drive the turbine generator. Borated demineralized water is circulated in the RC system at a flow and temperature consistent with achieving the reactor core thermal
| |
| -hydraulic performance. The water acts as a neutron moderator and as a neutron absorber. The RC system pressure is controlled by the use of the pressurizer, where water and steam are maintained in equilibrium by electrical heaters and water sprays.
| |
| The RC system pressure boundary provides a barrier against the release of radioactivity generated within the reactor and is designed to ensure a high degree of integrity throughout the life of the plant.
| |
| The intended functions of the RC system component types within the scope of license renewal include the following:
| |
| * serve as a pressure boundary and limit the release of fission products
| |
| * provide RC system pressure control and limit pressure transients
| |
| * provide the borated water used as a neutron moderator and as a neutron absorber
| |
| * provide a containment isolation function The following license renewal drawings provide the details of SSCs for the scope of license renewal and subject to an AMR:
| |
| * PID-1-CS-LR20722
| |
| * PID-1-RH-LR20662
| |
| * PID-1-SI-LR20450
| |
| * PID-1-VSL-LR20777
| |
| * PID-1-WLD-LR20221
| |
| * PID-1-RC-LR20841-PID-1-RC-LR20846
| |
| * PID-1-RH-LR20663
| |
| * PID-1-SS-LR20518 Structures and Components Subject to Aging Management Review 2-44
| |
| * PID-1-WLD-LR20218
| |
| * PID-1-SI-LR20448
| |
| * PID-1-SS-LR20520
| |
| * PID-1-WLD-LR20219 LRA Table 2.3.1
| |
| -1 lists the RC system component types that require an AMR.
| |
| 2.3.1.1.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concluded that the applicant appropriately identified the RC system components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the RC system components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.1.2 Reactor Vessel 2.3.1.2.1 Summary of Technical Information in the Application The reactor vessel is a vertical cylinder with a welded hemispherical bottom head and a removable, flanged hemispherical upper head. The vessel contains the core, core supporting structures, control rods, and other parts directly associated with the core. The vessel has four inlet and four outlet nozzles located in a horizontal plane just below the reactor vessel flange but above the top of the core. The coolant enters the vessel through the inlet nozzles, flows down the core barrel
| |
| -vessel wall annulus, turns at the bottom, and flows up through the core to the outlet nozzles.
| |
| Both the upper and lower reactor vessel heads contain penetrations, which are used for instrumentation or control devices. The lower reactor vessel head has penetrations for 58 incore nuclear instrumentation thimbles, while the reactor vessel upper head contains 79 control rod drive mechanism (CRDM) penetrations.
| |
| The reactor vessel is supported by steel pads on four of the coolant nozzles. The steel pads rest on steel base plates atop a support structure that is attached to the concrete foundation wall. There are three lifting lugs evenly spaced around the upper head, which are used to move it. The intended functions of the reactor vessel component types within the scope of license renewal include the following:
| |
| * serve as a pressure boundary for containing reactor coolant
| |
| * provide a barrier against the release of radioactivity
| |
| * support and contain the reactor core and core support structures
| |
| * support and guide reactor controls and instrumentation
| |
| * mitigate thermal shock The following license renewal drawing provides the details of SSCs for the scope of license renewal and subject to an AMR:
| |
| * PID-1-RC-LR20845 Structures and Components Subject to Aging Management Review 2-45 LRA Table 2.3.1
| |
| -2 lists the reactor vessel component types that require an AMR.
| |
| 2.3.1.2.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concluded that the applicant appropriately identified the reactor vessel components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the reactor vessel components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.1.3 Reactor Vessel Internals 2.3.1.3.1 Summary of Technical Information in the Application The reactor vessel internals are divided into three parts
| |
| -the lower core support structure, the upper core support structure, and the incore instrumentation support structure.
| |
| The reactor vessel internals support the core, maintain fuel alignment, limit fuel assembly movement, maintain alignment between fuel assemblies and CRDM, direct coolant flow past the fuel elements, direct coolant flow to the pressure vessel head, provide gamma and neutron shielding, and provide guides for the incore instrumentation.
| |
| The lower core support structure assembly consists of the core barrel, the core baffle, the lower core plate and support columns, the neutron shields pads, the core support that is welded to the core barrel, reactor fuel, and rod cluster control assemblies. The upper core support assembly consists of the top support plate assembly and the upper core plate, between which are contained support columns and guide tube assemblies. The incore instrumentation support structure consists of a guide tubing system to convey and support flux thimbles penetrating the vessel through the bottom.
| |
| The intended functions of the reactor vessel internals component types within the scope of license renewal include the following:
| |
| * support the reactor core
| |
| * maintain fuel alignment between fuel assemblies and control rods
| |
| * direct coolant flow to the vessel head
| |
| * provide gamma and neutron shielding
| |
| * guide the incore instruments LRA Table 2.3.1
| |
| -3 lists the reactor vessel internals component types that require an AMR.
| |
| 2.3.1.3.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concluded that the applicant appropriately identified the reactor vessel internals components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the reactor vessel internals components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| | |
| Structures and Components Subject to Aging Management Review 2-46 2.3.1.4 Steam Generators 2.3.1.4.1 Summary of Technical Information in the Application The steam generators transfer heat from the RC system to the secondary system during normal plant conditions, producing steam for use in the turbine generator. Each steam generator includes a primary section called the tube side, which includes components such as hemispherical channel head with a divider plate, tube sheet, and U
| |
| -tubes. The channel head makes up the bottom of the steam generator. The shell of the steam generator is a vertical cylinder. The tube sheet is welded to the bottom of the cylinder. The secondary section of the steam generator is referred to as the shell side. The upper shell houses the moisture separation equipment. The steam
| |
| -water mixture from the tube bundle passes through the moisture separator equipment to ensure that high
| |
| -quality steam is produced by the steam generators.
| |
| The intended functions of the steam generator component types within the scope of license renewal include the following:
| |
| * transfer heat from the RC system to the secondary systems
| |
| * provide RC system pressure boundary function
| |
| * confine radioactive material The following license renewal drawings provide the details of the SSCs for the scope of license renewal and subject to an AMR:
| |
| * PID-1-FW-LR20686
| |
| * PID-1-RC-LR20841-PID-1-RC-LR20844
| |
| * PID-1-MS-LR20580
| |
| * PID-1-MS-LR20581 LRA Table 2.3.1
| |
| -4 lists the steam generator component types that require an AMR.
| |
| 2.3.1.4.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA and UFSAR, the staff concluded that the applicant appropriately identified the steam generator components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the steam generator components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| | |
| ====2.3.2 Engineered====
| |
| Safety Features LRA Section 2.3.2 identifies the engineered safety features SCs subject to an AMR for license renewal. The applicant described the supporting SCs of the engineered safety features in the following LRA sections:
| |
| * Section 2.3.2.1, "Combustible Gas Control System"
| |
| * Section 2.3.2.2, "Containment Building Spray System" Structures and Components Subject to Aging Management Review 2-47
| |
| * Section 2.3.2.3, "Residual Heat Removal System"
| |
| * Section 2.3.2.4, "Safety Injection System" The staff's findings on review of LRA Sections 2.3.2.1
| |
| -2.3.2.4 are provided in SER Sections 2.3.2.1
| |
| -2.3.2.4, respectively.
| |
| 2.3.2.1 Combustible Gas Control System 2.3.2.1.1 Summary of Technical Information in the Application LRA Section 2.3.2.1 describes the combustible gas control system, which consists of subsystems that monitor the combustible gas concentrations in the containment and maintain a mixed containment atmosphere to ensure that hydrogen (H
| |
| : 2) concentrations remain below flammable levels following a LOCA. This is achieved by monitoring containment H 2 levels, mixing the containment atmosphere, recombining free H 2 with oxygen, or purging the containment atmosphere.
| |
| The containment atmosphere is monitored by two completely independent H 2 sampling and analysis systems, which are started after an accident. One means of combustible gas control in the containment is through the use of electric H 2 recombiners. Seabrook has a pair of recombiners, located at the perimeter of the operating floor inside the containment. Purging is accomplished by venting the containment gas and replacing it with clean compressed air from the plant air system. Compressed air is fed into the containment.
| |
| 2.3.2.1.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the combustible gas control system components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the combustible gas control system components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.2.2 Containment Building Spray System 2.3.2.2.1 Summary of Technical Information in the Application The containment building spray system is designed to remove the energy discharged to the containment following a LOCA or main steam line break, to prevent the containment pressure from exceeding design pressure, and to reduce and maintain containment temperature and pressure within acceptable limits. The containment building spray system provides for iodine removal by mixing sodium hydroxide (NaOH) with borated water from the refueling water storage tank (RWST) to limit the consequences of a LOCA to within the limits of 10 CFR Part 100, "Reactor Site Criteria," by providing a rapid reduction in containment elemental iodine concentration. The limits on NaOH volume and concentration ensure a pH value of between 8.5-11.0 for the solution recirculated within containment after a LOCA. This pH band minimizes the evolution of iodine and minimizes the effect of chloride and caustic stress corrosion on mechanical systems and components. 2.3.2.2.2 Conclusion
| |
| | |
| Structures and Components Subject to Aging Management Review 2-48 Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the containment building spray system components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the containment building spray system components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.2.3 Residual Heat Removal System 2.3.2.3.1 Summary of Technical Information in the Application The residual heat removal (RH) system transfers heat from the RCS to the primary component cooling water system to reduce the temperature of the RCS to the cold shutdown temperature, at a controlled rate, during the normal plant cooldown. The RH system is provided with two RH pumps and two residual heat exchangers arranged in two separate and independent flow paths. The RH system also makes up the low
| |
| -head safety injection (SI) portion of the emergency core cooling system (ECCS) by injecting borated water from the RWST into the RCS cold legs during the injection phase following a LOCA. The RH system is also used to transfer water between the refueling cavity and the RWST at the beginning and end of the refueling operations.
| |
| The intended functions of the RH system component types within the scope of license renewal include the following:
| |
| * form a part of the RCS pressure boundary
| |
| * remove decay heat in post
| |
| -accident and normal shutdown conditions
| |
| * provide protection against over
| |
| -pressurization and rupture of ECCS low
| |
| -pressure piping that could result in a LOCA
| |
| * provide borated water for RCS makeup in LOCA conditions The following license renewal drawings provide the details of SSCs for the scope of license renewal and subject to an AMR:
| |
| * PID-1-CBS-LR20233
| |
| * PID-1-RC-LR20841
| |
| * PID-1-RH-LR20663
| |
| * PID-1-VSL-LR20776
| |
| * PID-1-CS-LR20722
| |
| * PID-1-RC-LR20844
| |
| * PID-1-CS-LR20725
| |
| * PID-1-SI-LR20446-PID-1-RH-LR20662 Structures and Components Subject to Aging Management Review
| |
| *
| |
| * 2-49 PID-1-WLD-LR20221 PID SI-LR20450 LRA Table 2.3.2
| |
| -3 lists the RH system component types that require an AMR.
| |
| 2.3.2.3.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the RH system components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the RH system components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.2.4 Safety Injection System 2.3.2.4.1 Summary of Technical Information in the Application The SI system provides emergency core cooling to the reactor core as a part of the ECCS. The ECCS consists of three separate subsystems
| |
| -centrifugal charging (high head), SI (intermediate head), and RH (low head). Each subsystem consists of two redundant, 100 percent capacity trains. The ECCS also includes four accumulators (one on each RCS loop) and the RWST.
| |
| The SI system consists of accumulators, SI pumps, RWST, and associated piping and valves. Four accumulators, which are filled with borated water and pressurized with nitrogen gas, are connected to the four cold legs. The SI system has two phases of operation
| |
| -the injection phase and the recirculation phase.
| |
| The injection phase provides core cooling and additional negative reactivity following actuation. The SI pumps take their suction from the RWST during injection phase. The recirculation phase provides long
| |
| -term post-accident cooling by recirculating water from the containment sump.
| |
| The intended functions of the SI system component types within the scope of license renewal include the following:
| |
| * form part of the RCS pressure boundary
| |
| * provide source of emergency core cooling in response to a LOCA
| |
| * provide containment isolation functi on
| |
| * protect against over
| |
| -pressurization and rupture of ECCS low
| |
| -pressure piping
| |
| * provide mechanical support for safety
| |
| -related SSCs The following license renewal drawings provide the details of the SSCs for the scope of license renewal and subject to an AMR:
| |
| * PID-1-BRS-LR20854
| |
| * PID-1-RC-LR20844
| |
| * PID-1-SI-LR20446-PID-1-SI-LR20450 Structures and Components Subject to Aging Management Review *
| |
| * 2-50
| |
| * PID-1-WLD-LR20219
| |
| * PID-1-CBS-LR20233
| |
| * PID-1-RH-LR20662-PID-1-RH-LR20663 PID-1-WLD-LR20221 PID RC-LR20841
| |
| * PID-1-WLD-LR20218 LRA Table 2.3.3
| |
| -4 lists the SI component types that require an AMR.
| |
| 2.3.2.4.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the SI system components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the SI system components subject to an AMR, as required by 10 CFR 54.21(a)(1). 2.3.3 Auxiliary Systems LRA Section 2.3.3 identifies the auxiliary systems SCs subject to an AMR for license renewal.
| |
| The applicant described the supporting SCs of the auxiliary systems in the following LRA sections:
| |
| * Section 2.3.3.1, "Auxiliary Boiler System"
| |
| * Section 2.3.3.2, "Boron Recovery System"
| |
| * Section 2.3.3.3, "Chemical and Volume Control System"
| |
| * Section 2.3.3.4, "Chlorination System"
| |
| * Section 2.3.3.5, "Containment Air Handling System"
| |
| * Section 2.3.3.6, "Containment Air Purge System"
| |
| * Section 2.3.3.7, "Containment Enclosure Air Handling System"
| |
| * Section 2.3.3.8, "Containment Online Purge System"
| |
| * Section 2.3.3.9, "Control Building Air Handling System"
| |
| * Section 2.3.3.10, "Demineralized Water System"
| |
| * Section 2.3.3.11, "Dewatering System"
| |
| * Section 2.3.3.12, "Diesel Generator System"
| |
| * Section 2.3.3.13, "Diesel Generator Air Handling System"
| |
| * Section 2.3.3.14, "Emergency Feed Water Pump House Air Handling System"
| |
| * Section 2.3.3.15, "Fire Protection System"
| |
| * Section 2.3.3.16, "Fuel Handling System"
| |
| * Section 2.3.3.17, "Fuel Oil System"
| |
| * Section 2.3.3.18, "Fuel Storage Building Air Handling System"
| |
| * Section 2.3.3.19, "Hot Water Heating System"
| |
| * Section 2.3.3.20, "Instrument Air System"
| |
| * Section 2.3.3.21, "Leak Detection System"
| |
| * Section 2.3.3.22, "Mechanical Seal Supply System"
| |
| * Section 2.3.3.23, "Miscellaneous Equipment "
| |
| | |
| Structures and Components Subject to Aging Management Review
| |
| *
| |
| * 2-51
| |
| * Section 2.3.3.24, "Nitrogen Gas System"
| |
| * Section 2.3.3.25, "Oil Collection for Reactor Coolant Pumps System"
| |
| * Section 2.3.3.26, "Plant Floor Drain System"
| |
| * Section 2.3.3.27, "Potable Water System"
| |
| * Section 2.3.3.28, "Primary Auxiliary Building Air Handling System"
| |
| * Section 2.3.3.29, "Primary Component Cooling Water System" Section 2.3.3.30, "Radiation Monitoring System" Section 2.3.3.31, "Reactor Makeup Water System"
| |
| * Section 2.3.3.32, "Release Recovery System
| |
| "
| |
| * Section 2.3.3.33, "Resin Sluicing System"
| |
| * Section 2.3.3.34, "Roof Drains System"
| |
| * Section 2.3.3.35, "Sample System"
| |
| * Section 2.3.3.36, "Screen Wash System"
| |
| * Section 2.3.3.37, "Service Water System"
| |
| * Section 2.3.3.38, "Service Water Pump House Air Handling System"
| |
| * Section 2.3.3.39, "Spent Fuel Pool Cooling System"
| |
| * Section 2.3.3.40, "Switchyard System"
| |
| * Section 2.3.3.41, "Valve Stem Leak
| |
| -off System"
| |
| * Section 2.3.3.42, "Vent Gas System"
| |
| * Section 2.3.3.43, "Waste Gas System"
| |
| * Section 2.3.3.44, "Waste Processing Liquid System"
| |
| * Section 2.3.3.45, "Waste Processing Liquid Drains System" The staff's findings on review of LRA Sections 2.3.3.1
| |
| -2.3.3.45 are provided in SER Sections 2.3.3.1
| |
| -2.3.3.45, respectively.
| |
| During its review, the staff identified instances of boundary drawing errors where continuation notation for piping from one boundary drawing to another boundary drawing could not be identified or was incorrect.
| |
| By letter dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff issued RAI 2.3-01 and noted 13 instances where the staff was unable to identify the license renewal boundary because either the continuations were not provided or were incorrect or the continuation drawing was not provided. The applicant was asked to provide additional information to locate the continuations.
| |
| In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant provided sufficient information to locate the license renewal boundaries. No additional piping or component types were included in the scope of license renewal. The applicant also indicated that no continuation drawings were needed for piping that terminated at the nearby floor drains. The applicant stated components such as instrumentation and components found on vendor drawings were already included within the scope of license renewal but not depicted on the LRA drawings.
| |
| | |
| Structures and Components Subject to Aging Management Review *
| |
| * 2-52 Based on its review, the staff finds the applicant's response to RAI 2.3
| |
| -01 acceptable. No additional systems or components were required to be added to the scope of license renewal. Therefore, the staff's concern described in RAI 2.3
| |
| -01 is resolved.
| |
| 2.3.3.1 Auxiliary Boiler 2.3.3.1.1 Summary of Technical Information in the Application The auxiliary boiler system is a subsystem of the auxiliary steam system. The auxiliary boiler system provides steam to the auxiliary steam system, which in turn provides process steam for various plant heating loads.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-53 There are two main purposes of the auxiliary boiler system: to provide steam to the auxiliary steam system and to provide fuel oil to the fire pump house boiler. The fire pump house boiler provides steam to heat the fire water storage tank and provides steam to the fire pump house unit heaters.
| |
| The auxiliary boiler system consists of two package boilers, which include a de
| |
| -aerating heater with storage tank, boiler feed pumps, fuel oil pumps, and a blowdown tank. Also included are the fuel oil storage tank and the associated piping. The portion of the auxiliary boiler system that supplies oil to the fire pump house boiler consists of piping from the fuel oil storage tank to the fire pump house boiler and the fire pump house boiler oil pumps. 2.3.3.1.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant appropriately identified the auxiliary boiler system components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the auxiliary boiler system components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.2 Boron Recovery System 2.3.3.2.1 Summary of Technical Information in the Application The boron recovery system stores and processes reactor coolant effluent and reactor coolant grade drainage for reuse in the plant or for disposal offsite. The system maximizes recycling of effluent back to the plant and minimizes the release of radioactive material to the environment by proper cleanup and volume reduction methods. The system process is a combination of degasification, demineralization, filtration, and evaporation. The boron recovery system is designed as NNS class and non
| |
| -seismic Category I.
| |
| The boron recovery system is designed to do the following:
| |
| * process the reactor coolant letdown liquid generated by normal operations under either base loaded or load
| |
| -following conditions
| |
| * permit startup from a cold shutdown condition (For conservatism, the plant is assumed to be in end
| |
| -of-core-life conditions (50 parts per million (ppm) boron concentration), and evaporator availability is considered to be 75 percent of the time.)
| |
| * produce distillate from the boron evaporator with a maximum of 5 ppm boron and provide, by means of the boron demineralizers (mixed bed ion exchange units), the capability for reducing the boron concentration further, if so desired
| |
| * provide radioactivity decontamination and chemical purification such that, for reuse within the station, the system effluent meets the chemical purity requirements for recycled reactor makeup water and, for discharge from the station, the effluent meets required radioactivity release limitations
| |
| * accept and process any hydrogenated liquid drains collected in the primary drain tank
| |
| | |
| Structures and Components Subject to Aging Management Review 2-54 Other sources of liquid that can be transferred into the recovery test tanks (1
| |
| -BRS-TK-58-A and 1-BRS-TK-58-B) include effluent from a skid
| |
| -mounted waste liquid processing system should additional storage capacity be required prior to discharge.
| |
| 2.3.3.2.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.2, UFSAR Section 9.3.5, and the license renewal boundary drawings using the evaluation methodology described in SER Section 2.3 and the guidance in SRP
| |
| -LR Section 2.3. In addition to the continuation issue identified in RAI 2.3-01, as described in Section 2.3.3, the staff's review identified an area in which additional information was required to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAI, as discussed below.
| |
| In RAI 2.3.3.2
| |
| -01, dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff noted on LRA drawing PID CS-LR20724, at location G
| |
| -11, a section of safety
| |
| -related 3 in. piping connected to nonsafety
| |
| -related 3 in. piping at valve V
| |
| -633. The piping section, located between valve V
| |
| -633 and the seismic anchor located at G
| |
| -9, is within the scope of license renewal for 10 CFR 54.4(a)(2). However, there is a 1
| |
| -in. line that connects to the 3 in. nonsafety-related piping between valve V633 and the seismic anchor. This line continues and connects to a 3
| |
| -in. piping section, which connects into a 3
| |
| -in. line and 3/4 in. line at location E
| |
| -9. At location D
| |
| -12 of LRA drawing PID CS-LR20724, the 3
| |
| -in. line continues through valves V
| |
| -634, V-635, V-636 to a piping section that continues to LRA drawing PID BRS-LR20856.
| |
| This piping section is not depicted within the scope of license renewal. Additionally, at location D-12 of LRA drawing PID CS-LR20724, the 3/4 in. line continues through valve V
| |
| -835 to LRA drawing PID SS-LR20519. Seismic anchors could not be located between the start of the 1
| |
| -in. line (at location G
| |
| -9 on LRA drawing PID CS-LR20724) and the 3 in. and 3/4 in. continuations (at location D
| |
| -12 on LRA drawing PID CS-LR20724). The applicant was asked to provide the location of the first seismic anchors on nonsafety
| |
| -related piping past the safety and nonsafety interface for the above locations.
| |
| In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant clarified why the seismic anchors were not depicted on the LRA drawings. The applicant described the pipe support anchors, 303
| |
| -A-01 and 302
| |
| -A-20, as being located beyond the safety and nonsafety interface to ensure that failure of the nonsafety
| |
| -related piping does not affect the safety
| |
| -related piping. The applicant also described the 302
| |
| -A-20 anchor as being located at the tee intersection of the boron recovery system and chemical and volume control system (CS), which equally restrains the 1
| |
| -in. piping. The applicant further indicated that the entire nonsafety
| |
| -related piping is included within the scope of license renewal and subject to an AMR until the piping exits the primary auxiliary building and enters the waste process building, in which no seismic anchors are needed.
| |
| Based on its review, the staff finds the applicant's response to RAI 2.3.3.2
| |
| -01 acceptable because the staff confirmed that the description given in the applicant's RAI response is consistent with its scoping methodology in LRA Section 2.1.2.2.2 for nonsafety
| |
| -related piping attached to safety
| |
| -related piping. Therefore, the staff's concern described in RAI 2.3.3.2
| |
| -01 is resolved.
| |
| 2.3.3.2.3 Conclusion
| |
| | |
| Structures and Components Subject to Aging Management Review 2-55 The staff reviewed the LRA, UFSAR, and RAI response, and license renewal boundary drawings to determine whether the applicant had identified all components within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all components subject to an AMR. On the basis of its review, the staff concludes the applicant appropriately identified the boron recovery system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
| |
| 2.3.3.3 Chemical and Volume Control System 2.3.3.3.1 Summary of Technical Information in the Application The chemical and volume control system (CS) consists of the following subsystems:
| |
| * high-head injection part of the ECCS
| |
| * charging, letdown, and seal water system
| |
| * reactor coolant purification and chemistry control system
| |
| * reactor makeup control system The CS is a support system for the RCS during all normal modes of plant operation. Th e centrifugal charging pumps serve as the high head SI pumps in the ECCS. The charging and letdown functions of the CS are employed to maintain a programmed level in the RCS pressurizer, thus maintaining proper reactor coolant inventory during all phases of plant operations. A portion of the charging flow is directed to the RCP seals via a seal water injection filter. The reactor coolant purification and chemistry control system maintains reactor coolant chemistry within Electric Power Research Institute (EPRI)-specified guidelines. The soluble neutron absorber (boric acid) concentration is controlled by the reactor makeup control system. The CS consists of three charging pumps; a letdown heat exchanger; a regenerative heat exchanger; a volume control tank; and associated pumps, piping, valves, and filters. The CS also includes demineralizer vessels and chemical tanks associated with control of water chemistry in the RCS. The CS includes provisions for recycling reactor
| |
| -grade water and boric acid. The intended functions of the CS component types within the scope of license renewal include the following:
| |
| * maintain the RCS pressure boundary
| |
| * maintain water inventory in the RCS
| |
| * vary boron concentration for reactivity control
| |
| * supply water to the RCP seals for cooling and sealing purposes
| |
| * provide containment isolation function
| |
| * provide high head SI for emergency core cooling The following license renewal drawings provide the details of SSCs for the scope of license renewal and subject to an AMR:
| |
| | |
| Structures and Components Subject to Aging Management Review 2-56
| |
| * PID-1-B RS-LR20854
| |
| * PID-1-CS-LR20722-PID-1-CS-LR20729
| |
| * PID-1-CBS-LR20233
| |
| * PID-1-RH-LR20663
| |
| * PID-1-RC-LR20846
| |
| * PID-1-SI-LR20446-PID-1-SI-LR20449
| |
| * PID-1-RS-LR20252
| |
| * PID-1-SS-LR20519
| |
| * PID-1-WLD-LR20218
| |
| * PID-1-WLD-LR20223
| |
| * PID-1-CC-LR20212
| |
| * PID-1-RH-LR20662
| |
| * PID-1-RC-LR20841-PID-1-RC-LR20846
| |
| * PID-1-SF-LR20483
| |
| * PID-1-SS-LR20518
| |
| * PID-1-VSL-LR20775-PID-1-VSL-LR20777
| |
| * PID-1_WLD-LR20219
| |
| * PID-1-WLD-LR20222 LRA Table 2.3.3
| |
| -3 lists the CS component types that require an AMR.
| |
| 2.3.3.3.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the CS component within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the CS component subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.4 Chlorination System 2.3.3.4.1 Summary of Technical Information in the Application The chlorination (CL) system provides sodium hypochlorite solution for injection into the circulating water system. Provisions for continuous low
| |
| -level CL and heat treatment of the tunnels are included for control of fouling by marine organisms.
| |
| Sodium hypochlorite is injected into a common header that receives flow from the screen wash system pumps. The flow from this common header flows to the following locations:
| |
| * intake tunnel
| |
| * intake transition structure
| |
| * discharge transition structure
| |
| * circulating water pump bays
| |
| * service water pump bays The CL system is nonsafety related.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-57 2.3.3.4.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the CL system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the CL system mechanical components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.5 Containment Air Handling System 2.3.3.5.1 Summary of Technical Information in the Application The containment air handling system is composed of three subsystems
| |
| -the containment structure cooling system, the containment recirculation and filter system, and the CRDM cooling system.
| |
| The containment structure cooling system is designed to maintain the normal ambient air temperature in the containment structure at or below 120° F.
| |
| The containment recirculation and filter system is normally used to filter contaminated air within containment prior to personnel entry and whenever it is desired to reduce airborne particulate contamination and radioactive iodine. The filter subsystem, when operated in conjunction with the pre-entry purge subsystem, reduces the airborne iodine to an acceptable level, permitting access to containment within 24 hours after the reactor is shutdown. The fans, ductwork, and dampers associated with the containment recirculation subsystem are redundant, and, as such, a single failure will not render the system inoperative. Failure of the filter unit of the containment recirculation subsystem will not affect safe operation or shutdown of the plant since the air cleaning unit has no safety design bases.
| |
| The CRDM cooling system is designed to induce supply air into the CRDM shroud at or below 120 ° F. 2.3.3.5.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the containment air handling system components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the containment air handling system components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.6 Containment Air Purge System 2.3.3.6.1 Summary of Technical Information in the Application The containment air purge system is composed of three subsystems
| |
| -the containment structure air purge and heating subsystem, the pre
| |
| -entry purge subsystem, and the refueling purge subsystem.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-58 The containment air purge and heating subsystem employs two supply fans and two exhaust fans with the common supply and exhaust ductwork. Each set consists of (a) a supply air fan and exhaust air fan, each with pneumatically operated dampers, and (b) a common ductwork system, which includes the refueling purge supply and heating subsystem and the pre
| |
| -entry purge subsystem.
| |
| During pre
| |
| -entry purge, a single fan supplies pre
| |
| -entry purge air to the containment area using common supply ductwork. A single exhaust fan pulls air from containment through common exhaust ductwork and discharges directly to the unit plant vent after first passing through the filter unit and the containment air purge air cleaning unit.
| |
| In the refueling purge subsystem, a single fan supplies refueling purge and heating (when required) air to the containment area during the refueling operation using, as described above, the same ductwork as the pre
| |
| -entry purge system. Dampers are used to isolate the nonoperating system, in this case, the pre
| |
| -entry purge. The 40,000 cubic feet per minute (cfm) exhaust airflow of the refueling purge subsystem first passes through a filter unit before discharging to the plant vent. 2.3.3.6.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the containment air purge system components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the containment air purge system components subject to an AMR, as required by 10 CFR 54.21(a)(1). 2.3.3.7 Containment Enclosure Air Handling System 2.3.3.7.1 Summary of Technical Information in the Application The containment enclosure air handling system removes heat from areas associated with the containment enclosure, creates a negative pressure in the containment enclosure structure to capture post
| |
| -accident leakage from the containment and contiguous areas, and filters the effluent prior to release from the plant vent. The containment enclosure and adjoining areas cooling systems are designed to remove equipment heat from the following areas during normal and emergency operation:
| |
| * charging pump areas
| |
| * SI pump areas
| |
| * RH equipment areas
| |
| * containment spray pump and heat exchanger equipment areas
| |
| * mechanical penetration area
| |
| * containment enclosure ventilation equipment area
| |
| * H 2 analyzer room and electrical room areas
| |
| * RH vault stairway area
| |
| * electrical tunnel personnel walkway (electrical) area
| |
| | |
| Structures and Components Subject to Aging Management Review 2-59 The containment enclosure cooling units maintain the first six areas (charging pump areas, SI pump areas, RH equipment areas, containment spray pump and heat exchanger equipment areas, mechanical penetration area, and containment enclosure ventilation equipment area) at, or below, the safety
| |
| -related equipment's maximum design operating temperatures during normal operation and following a LOCA, loss of offsite power, high and moderate pipe breaks, SSE, and tornados.
| |
| The H 2 analyzer and electrical room supply fans maintain area 7 at or below the safety
| |
| -related equipment's maximum design operating temperatures during normal operation and following a LOCA, loss of offsite power, high and moderate pipe breaks, and an SSE.
| |
| The RH vault stairway chilled water cooling units maintain area 8 at or below safety
| |
| -related equipment's maximum design operating temperature during normal operation. This temperature is 104° F, coincident with an outside temperature of 88° F. The system provides auxiliary cooling to maintain area temperatures below 104 °F. The cooling system is nonsafety-related and is operated, as required, to maintain the desired area temperature.
| |
| The electrical tunnel personnel walkway chilled water cooling units maintain area 9 at or below safety-related equipment's maximum design operating temperature during normal operation. This temperature is 104 °F, coincident with an outside temperature of 88° F. The system provides auxiliary cooling to maintain area temperatures below 104 °F. The cooling system is nonsafety-related and is operated, as required, to maintain the desired area temperature.
| |
| 2.3.3.7.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the containment enclosure air handling system components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the containment enclosure air handling system components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.8 Containment Online Purge System 2.3.3.8.1 Summary of Technical Information in the Application The containment online purge system provides supply air to the containment during normal operation and exhaust air from the containment to the plant vent filter. Valves in the exhaust line can be adjusted to establish containment pressure. The containment online purge subsystem supply air fan draws filtered, preheated air from the primary auxiliary building mechanical room at elevation 53 feet (ft) and distributes it through an 8
| |
| -in. supply air duct into the containment.
| |
| The online purge subsystem exhaust equipment collects air from the containment and exhausts it to the normal exhaust filter unit located in the primary auxiliary building. This filtered air is then discharged to the plant vent. The purge exhaust valves are NNS
| |
| -related, in accordance with American National Standards Institute (ANSI) B16.5.
| |
| 2.3.3.8.2 Conclusion
| |
| | |
| Structures and Components Subject to Aging Management Review 2-60 Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the containment online purge system components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the containment online purge system components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.9 Control Building Air Handling System 2.3.3.9.1 Summary of Technical Information in the Application Seabrook's control room complex occupies the entire 75
| |
| -ft elevation of the control building.
| |
| The HVAC systems that service the control room complex are described below and in UFSAR Section 6.4, "Habitability Systems." In addition, the redundant filter systems integral to the emergency makeup air and filtration subsystem are detailed in the UFSAR. The control room complex HVAC system consists of the following subsystems:
| |
| * control room safety
| |
| -related air conditioning subsystem
| |
| * control room nonsafety
| |
| -related chilled water system
| |
| * computer room air conditioning subsystem
| |
| * control room normal makeup air subsystem
| |
| * control room emergency air makeup and filtration subsystem
| |
| * control room exhaust and static pressure control subsystem
| |
| * control room air conditioning subsystem The control room air conditioning subsystem includes both safety
| |
| -related and nonsafety
| |
| -related cooling subsystems. The safety
| |
| -related and nonsafety
| |
| -related cooling subsystems share a common recirculating air system located on elevation 75 ft within the control room complex. The safety
| |
| -related control room air conditioning subsystem consists of two full
| |
| -sized identical air cooling trains that are independently electrically powered. Each train consists of the following:
| |
| * a 100 percent capacity electric motor
| |
| -driven water chiller
| |
| * two 100 percent capacity chilled water circulating pumps
| |
| * a 100 percent capacity chiller condenser exhaust fan
| |
| * a back draft damper
| |
| * a 100 percent capacity air handling unit located in the recirculated control room air cooling stream
| |
| * interconnecting piping, expansion tank, and I&Cs 2.3.3.9.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the control building air handling system components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant Structures and Components Subject to Aging Management Review 2-61 adequately identified the control building air handling system components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.10 Demineralized Water System 2.3.3.10.1 Summary of Technical Information in the Application The demineralized water system serves no safety
| |
| -related functions. It is designed as an NNS, non-seismic Category I system, except for the containment penetration piping and containment isolation valves, which are designed in accordance with safety Class 2, seismic Category I requirements. Additionally, the makeup water piping connections to the primary component cooling water head tanks are designed in accordance with safety Class 3, seismic Category I requirements. In addition, the interface piping with the condensate storage tank and the thermal barrier loop head pipe is safety Class 3.
| |
| The system is designed to provide a sufficient supply of demineralized water at a quality required for operation, makeup, and maintenance of the plant.
| |
| Water from the water treatment subsystem is directed to either a 500,000
| |
| -gallon (gal.) or 200,000-gal. demineralized water storage tank. From here, the water can be transferred to the condensate storage tank or distributed throughout the unit by means of the demineralized water system. If the demineralized water storage tanks are full or not available, it is possible to bypass these tanks and go directly from the water treatment plant to the condensate storage tank. The demineralized water transfer subsystem supplies initial fill and makeup to the various services within the turbine, administration, containment, primary auxiliary, fuel storage, and waste processing buildings, as well as the condensate polishing facility. These services include reactor makeup, primary and secondary component cooling water, auxiliary boiler deaerator makeup, condensate polishing regeneration, emergency shower and eye wash stations, generator stator cooling, and maintenance flushing of systems and component s located within the plant.
| |
| 2.3.3.10.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the demineralized water system components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the demineralized water system components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.11 Dewatering System 2.3.3.11.1 Summary of Technical Information in the Application Seabrook was not originally designed with a dewatering system because it was believed that the in-leakage prevention methods described in UFSAR Section 3.4.1.1, "Flood Protection Measures for Seismic Category I Structures," would be adequate to prevent water ingress. Over the years, it has become evident that the mitigation methods were not completely effective at preventing in
| |
| -leakage.
| |
| Structures and Components Subject to Aging Management Review 2-62 A plant dewatering system has been installed, which can further mitigate in
| |
| -leakage of groundwater in the lower elevations of the plant. The purpose is to routinely pump water from beneath the plant structures, to reduce the static hydraulic head outside the building concrete, and to reduce the in
| |
| -leakage. This allows the original mitigative measures to function properly.
| |
| A pump is installed in the existing well at (+) 7
| |
| -ft elevation of the primary auxiliary building. This pump discharges the water to the roof drains system, which then flows to the storm drain system and out to circulating water for discharge.
| |
| Existing pipe penetrations located in the (-) 26-ft elevation of the emergency feedwater pump house (EFPH) have been used as a groundwater low point. These penetrations have been directed to a nearby sump. This sump discharges to the existing plant storm drain system. A pump is installed in the RH vault "B" stairwell at (-) 61-ft elevation of the equipment vault. This pump discharges the water to the roof drains system, which then flows to the storm drain system and out to circulating water for discharge. Routine monitoring of this flow path is performed per station operating procedures.
| |
| A pump is installed in the containment annulus at (-) 32-ft elevation. This pump discharges the ground water in the containment annulus to the roof drain system. The connection to the drain system is installed at 240 degrees azimuth of the containment annulus. Routine monitoring of this flow path is performed per station operating procedures.
| |
| A ground water collection tank and pump are installed in the "B" electrical tunnel, west stairwell at (-) 20-ft elevation. The pump discharges the water to the turbine building roof drains system, which then flows to the storm drain system and out to circulating water for discharge via the outfall. Routine monitoring of this flow path is performed per station operating procedure.
| |
| 2.3.3.11.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the dewatering system components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the dewatering system components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.12 Diesel Generator 2.3.3.12.1 Summary of Technical Information in the Application The standby power supply is provided by two redundant diesel engine generators of identical design and characteristics, which supply onsite power of sufficient capacity and capability to reliably shut down the reactor. The diesel generator system includes the skid
| |
| -mounted diesel generators and their auxiliaries.
| |
| 2.3.3.12.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.12; UFSAR Section 8.3, Section 9.5, and Table 7.5
| |
| -1; and the license renewal boundary drawings, using the evaluation methodology described in Structures and Components Subject to Aging Management Review 2-63 SER Section 2.3 and the guidance in SRP
| |
| -LR Section 2.3. The staff's review identified an area in which additional information was required to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAI, as discussed below. In RAI 2.3.3.12
| |
| -01, dated January 5, 2011, the staff noted on LRA drawings PID-1-DG-LR20460 and PID DG-LR20465, at location F
| |
| -10, a pulsation damper and cooling pipe within the scope of license renewal under 10 CFR 54.4(a)(1). The same LRA drawings, at location B
| |
| -7, depict upper and lower bearing gear interlock components within the scope of license renewal under 10 CFR 54.4(a)(1). However, none of the above components were included in LRA Table 2.3.3
| |
| -12. The applicant was asked to justify the exclusion of these components from LRA Table 2.3.3
| |
| -12. In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant indicated that the pulsation damper and cooling pipe components are in
| |
| -scope for license renewal and were grouped under component type "piping and fittings" in Table 2.3.3-12. The applicant further stated that the upper and lower bearing gear interlock components were also in-scope for license renewal and were grouped under component type "valve body" in Table 2.3.3
| |
| -12. Based on its review, the staff finds the applicant's response to RAI 2.3.3.12
| |
| -1 acceptable because the staff confirmed that the component types, "piping and fittings" and "valve body," are included on LRA Table 2.3.3
| |
| -12. Therefore, the staff's concern described in RAI 2.3.3.12
| |
| -1 is resolved.
| |
| 2.3.3.12.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI response, and license renewal boundary drawings, to determine whether the applicant had identified all components within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all components subject to an AMR. On the basis of its review, the staff concludes the applicant appropriately identified the diesel generator system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
| |
| 2.3.3.13 Diesel Generator Air Handling System 2.3.3.13.1 Summary of Technical Information in the Application The diesel generator building heating and ventilating system removes heat generated in the building during normal and emergency conditions and maintains the design winter indoor building temperature. Ventilation is provided by the diesel generator air handling system. Electric heaters provided in each day tank room are included in the diesel generator air handling system. The remainder of the diesel generator building heating function is provided by hot water heating (HW) and is evaluated separately.
| |
| 2.3.3.13.2 Conclusion
| |
| | |
| Structures and Components Subject to Aging Management Review 2-64 Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the diesel generator air handling system components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the diesel generator air handling system components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.14 Emergency Feedwater Pump House Air Handling System 2.3.3.14.1 Summary of Technical Information in the Application The function of the heating and ventilating systems is to maintain the inside temperature of the emergency feedwater pump house within design limits for both normal and emergency feedwater system operation during summer and winter.
| |
| The ventilation function is provided by the Emergency Feedwater Pump House Air Handling (EPA) system. The heating function is provided by the HW system and is evaluated separately.
| |
| The emergency feedwater pump house is ventilated and cooled with outside air, supplied through one of the two redundant supply fans and its tornado gravity intake damper with pneumatic test operator and exhausted through its tornado exhaust damper with pneumatic operator. Each fan and its exhaust damper are controlled by a separate room thermostat. Setpoints are staggered to avoid simultaneous operation of redundant equipment. The emergency feedwater pump house high temperature is alarmed.
| |
| The redundant, seismic Category I, safety Class 3, pump room supply fans, supply and exhaust dampers, and the Class 1E fan motors, each with electrical power from a separate engineered safety features power source, ensure continued ventilation should an SSE, loss of offsite power, or single failure occur. Loss of air or electrical power to the pneumatically
| |
| -operated supply and exhaust dampers will cause them to fail open.
| |
| 2.3.3.14.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the EPA system components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the EPA system components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.15 Fire Protection System 2.3.3.15.1 Summary of Technical Information in the Application The fire protection system is a nonsafety
| |
| -related system designed to detect and alarm, control, and extinguish fires that may occur. To accomplish this end, the concept of defense in depth is a criterion for design. This concept, applied to fire protection, aims at a balanced program, which will do the following:
| |
| * prevent fires from starting
| |
| | |
| Structures and Components Subject to Aging Management Review 2-65
| |
| * detect fires quickly and quickly suppress those that occur, thus limiting their damage
| |
| * design and locate plant equipment such that, if a fire occurs and burns for a long time, essential plant activities will still be performed
| |
| * ensure that neither inadvertent operation nor failure of a fire protection system will induce a failure of any safe ty-related system LRA Section 2.3.3.15 describes the fire protection systems. LRA Table 2.3.3
| |
| -15 identifies the component types within the scope of license renewal and subject to an AMR.
| |
| The fire protection system includes nonsafety
| |
| -related components that are attached to or located near safety
| |
| -related SSCs, whose failure creates a potential for spatial interaction that could prevent the satisfactory accomplishment of a function identified in 10 CFR 54.4(a)(1). Therefore, the fire protection system satisfies the scoping criteria of 10 CFR 54.4(a)(2). The fire protection system is relied upon to demonstrate compliance with, and satisfies the 10 CFR 54.4(a)(3) scoping criteria for, the fire protection (10 CFR 50.48) regulated event.
| |
| 2.3.3.15.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.15, the UFSAR, and LRA drawings using the evaluation methodology described in SER Section 2.3 and guidance in SRP
| |
| -LR, Section 2.3. The staff also reviewed UFSAR Section 9.5.1, "Fire Protection System," and Fire Protection Evaluation and Comparison to Branch Technical Position (BTP) APCSB 9.5
| |
| -1, Appendix A Report (i.e., approved fire protection program, a point
| |
| -by-point comparison with Appendix A) to the BTP, APCSB 9.5
| |
| -1, "Guidelines for Fire Protection for Nuclear Power Plants," May 1, 1976.
| |
| The staff also reviewed the following fire protection documents, cited in the CLB, listed in the Seabrook Operating License Condition 2.F:
| |
| * NUREG-0896, "Safety Evaluation Report related to the operation of Seabrook Station, Units 1 and 2," dated March 1983
| |
| * NUREG-0896, "Safety Evaluation Report related to the operation of Seabrook Station, Units 1 and 2," Supplement 4, dated May 1986
| |
| * NUREG-0896, "Safety Evaluation Report related to the operation of Seabrook Station, Units 1 and 2," Supplement 5, dated July 1986
| |
| * NUREG-0896, "Safety Evaluation Report related to the operation of Seabrook Station, Units 1 and 2," Supplement 6, dated October 1986
| |
| * NUREG-0896, "Safety Evaluation Report related to the operation of Seabrook Station , Units 1 and 2," Supplement 7, dated October 1987
| |
| * NUREG-0896, "Safety Evaluation Report related to the operation of Seabrook Station, Units 1 and 2," Supplement 8, dated May 1989 During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any components with intended functions pursuant to 10 CFR 54.4(a). The staff then reviewed those components that the applicant identified as within the scope of license renewal to verify that Structures and Components Subject to Aging Management Review 2-66 the applicant had not omitted any passive or long
| |
| -lived components subject to an AMR, in accordance with 10 CFR 54.21(a)(1).
| |
| During its review of LRA Section 2.3.3.15, the staff identified areas in which additional information was necessary to complete its review of the applicant's scoping and screening results. The applicant responded to the staff's RAIs, as discussed below.
| |
| In RAI 2.3.3.15
| |
| -1, dated November 18, 2010 (ADAMS Accession No. ML103090308), the staff stated that LRA drawing PID FP-LR20270 shows that sprinkler systems at locations C
| |
| -4 to H-4 are out of scope (i.e., not colored in red). The staff requested that the applicant verify if these sprinkler systems, installed in various areas of the plant, are in the scope of license renewal, in accordance with 10 CFR 54.4(a), and subject to an AMR, in accordance with 10 CFR 54.21(a)(1). If they are excluded from the scope of license renewal and not subject to an AMR, the staff asked that the applicant justify the exclusion.
| |
| In a letter dated December 3, 2010 (ADAMS Accession No. ML103400259), the applicant responded to RAI 2.3.3.15
| |
| -1 by stating the following:
| |
| The sprinkler systems located on drawing PID FP-LR20270, locations C
| |
| -4 to H-4, are not in scope of License Renewal because they do not provide a function credited in Appendix R safe shutdown analysis and do not provide a pressure boundary function needed to support the Appendix R suppression systems. All other sprinklers located in the turbine building are in scope because they perform a pressure boundary function necessary to permit the required Appendix R fire suppression systems to function properly.
| |
| In evaluating this response, the staff found that it was inadequate and review of LRA Section 2.3.3.15 could not be completed. The applicant's response to RAI 2.3.3.15
| |
| -1 was inconsistent with the UFSAR Revision 13, Section 9.5.1.2(c)(7), "Manually Operated Pre
| |
| -Action Sprinkler Systems," which states that manually
| |
| -operated sprinkler systems are provided for areas containing turbine bearings and lube oil piping from turbine bearings to guard. Therefore, by letter to the applicant dated March 30, 2011, the staff issued a followup RAI concerning the specific issues to determine if the applicant properly applied the scoping criteria of 10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1).
| |
| In the followup RAI (ADAMS Accession No. ML110700018), the staff stated that the fire suppression systems discussed above appeared to be credited in the approved Fire Protection Program (UFSAR Section 9.5.1) for fire suppression activities. The staff explained that the applicant's analysis of fire protection regulations does not completely capture the fire protection SSCs required for compliance with 10 CFR 50.48. The scope of fire protection SSCs, required for compliance with 10 CFR 50.48 and General Design Criterion (GDC) 3, goes beyond preserving the ability to maintain safe
| |
| -shutdown in the event of a fire. The staff stated that the exclusion of fire protection SSCs, on the basis that the intended function is not required for the protection of safe
| |
| -shutdown equipment or safety
| |
| -related equipment, is not acceptable if the fire protection SSC is required for compliance with 10 CFR 50.48.
| |
| In its response, dated April 22, 2011 (ADAMS Accession No. ML11115A116), the applicant stated that the sprinkler systems downstream of valves 1
| |
| -FP-V-792 and 1-FP-V-800 at locations C
| |
| -4 to H-4 on boundary drawing PID-1-FP-LR20270 have been added to the license renewal, and the LRA has been revised.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-67 Based on its review, the staff finds the applicant's response to the followup RAI acceptable because it indicated that the sprinkler system in question is within the scope of license renewal and subject to an AMR. The staff's concern described in RAI 2.3.3.15
| |
| -1 is resolved.
| |
| In RAI 2.3.3.15
| |
| -2, dated November 18, 2010 (ADAMS Accession No. ML103090308), the staff stated that LRA drawing PID FP-LR20274 shows that several yard fire hydrants and post
| |
| -indicator valves are out of scope (i.e., not colored in red). The staff believed that yard fire hydrants and post
| |
| -indicator valves have the fire protection
| |
| -intended functions required to be compliant with 10 CFR 50.48, as stated in 10 CFR 54.4. The fire hydrants and post
| |
| -indicator valves also serve as the pressure boundary for the fire protection water supply system.
| |
| Further, NUREG
| |
| -0896, "Safety Evaluation Report related to the operation of Seabrook Station, Units 1 and 2,"
| |
| dated March 1983, Section 9.5.1.5, "Fire Detection and Suppression," on page 9-47, states that "-[y]ard hydrants are provided at intervals of 250 ft along the fire protection water supply loop, approximately 40 ft from the buildings-Each yard hydrant is provided with an isolation valve to facilitate hydrant maintenance and repairs without shutting down any part of the fire water supply system-"
| |
| The staff requested that the applicant verify if the yard hydrants and post
| |
| -indicator valves are in the scope of license renewal, in accordance with 10 CFR 54.4(a), and if they are subject to an AMR, in accordance with 10 CFR 54.21(a)(1). If they are excluded from the scope of license renewal and are not subject to an AMR, the staff requested that the applicant justify the exclusion.
| |
| In a letter dated December 3, 2010 (ADAMS Accession No. ML103400259), the applicant responded to RAI 2.3.3.15
| |
| -2 by stating the following:
| |
| The yard fire hydrants required to support Unit 1 compliance with 10 CFR 50.48 and Appendix R safe shutdown are included in scope of License Renewal (See PID-1-FP-LR20274 demarcation line) and are subject to an AMR in accordance with 10 CFR 54.21(a)(1). The yard fire hydrants supporting Unit 2 and the site support buildings are not required for compliance with 10 CFR 50.48 and Appendix R safe shutdown and do not have a License Renewal
| |
| -intended function and are not in scope of license renewal. Construction on Seabrook Station Unit 2 was effectively terminated in 1984 and its construction permit was allowed to expire in October 1988. All of the post indicator valves located on the fire main ring header and any branch header isolation post indicator valves are in scope of License Renewal and are subject to an AMR in accordance with 10 CFR 54.21(a)(1). All other post indicating valves that supply support buildings and branch headers are not required for compliance with 10 CFR 50.48 or Appendix R safe shutdown and do not have a License Renewal
| |
| -intended function and are not in scope of license renewal.
| |
| The staff reviewed the applicant's response to RAI 2.3.3.15
| |
| -2, which confirmed that the yard fire hydrants and post
| |
| -indicator valves in question are associated with Seabrook Unit 2 (Seabrook Unit 2 construction was terminated in 1984 and its construction permit expired in October 1988). They are not required for Unit 1 compliance with 10 CFR 50.48 and
| |
| | |
| Structures and Components Subject to Aging Management Review 2-68 Appendix R safe shutdown, and they do not have a license renewal
| |
| -intended function and are not within the scope of license renewal. Therefore, the staff's concern described in RAI 2.3.3.15-2 is resolved.
| |
| In RAI 2.3.3.15
| |
| -3, dated November 18, 2010 (ADAMS Accession No. ML103090308), the staff stated that Section 9.5.1.6, "Fire Protection of Specific Plant Areas," of NUREG
| |
| -0896, "Safety Evaluation Report related to the operation of Seabrook Station, Units 1 and 2," dated March 1983, on page 9
| |
| -48, states that "-the applicant committed to provide oil collection systems for each RCP in accordance with Section III.O Appendix R-" LRA Section 2.3.3.15 did not discuss scoping and screening results of RCP oil collection systems and their associated components.
| |
| The staff requested that the applicant verify if the RCP oil collection systems and their associated components are in the scope of license renewal, in accordance with 10 CFR 54.4(a), and subject to an AMR, in accordance with 10 CFR 54.21(a)(1). If RCP oil collection systems and their associated components are excluded from the scope of license renewal and not subject to an AMR, the staff requested that the applicant justify the exclusion.
| |
| In a letter dated December 3, 2010 (ADAMS Accession No. ML103400259), the applicant responded to RAI 2.3.3.15
| |
| -3 by stating the following:
| |
| The Reactor Coolant Oil collection system is in scope for fire protection (10 CFR 54.4 (a)(3)) and is subject to an AMR in accordance with 10 CFR 54.21(a)(1). See LRA Section 2.3.3.25, "Oil Collection for Reactor Coolant Pumps System;" on page 2.3
| |
| -189. The staff reviewed the applicant's response to RAI 2.3.3.15
| |
| -3, including verification of the referenced discussion on LRA page 2.3
| |
| -189, which confirmed that the RCP oil collection systems and their associated components have been included in the scope of license renewal and are subject to an AMR. Therefore, the staff's concern described in RAI 2.3.3.15
| |
| -3 is resolved.
| |
| In RAI 2.3.3.15
| |
| -4, dated November 18, 2010 (ADAMS Accession No. ML103090308), the staff stated that Section 9.5.1.6, "Fire Protection of Specific Plant Areas," of NUREG
| |
| -0896, "Safety Evaluation Report Related to the Operation of Seabrook Station, Units 1 and 2," dated March 1983, on page 9
| |
| -52, "Cable Spreading Room," states that "-[a] manual smoke ventilation system has been provided to exhaust the cable spreading room in the event of a fire-" LRA Section 2.3.3.15 did not discuss scoping and screening results of the cable spreading room (CSR) manual smoke ventilation system and its associated components.
| |
| The staff requested that the applicant verify if the CSR manual smoke ventilation system and its associated components are in the scope of license renewal, in accordance wit h 10 CFR 54.4(a), and subject to an AMR, in accordance with 10 CFR 54.21(a)(1). If the CSR manual smoke ventilation system and its associated components are excluded from the scope of license renewal and not subject to an AMR, the staff requested that the applicant justify the exclusion.
| |
| In a letter dated December 3, 2010 (ADAMS Accession No. ML103400259), the applicant responded to RAI 2.3.3.15
| |
| -4 by stating the following:
| |
| | |
| Structures and Components Subject to Aging Management Review 2-69 The manual smoke removal system is not in scope of License Renewal. The fans (1-CBA-FN-17 and 1 -CBA-FN-18) used for smoke removal are not credited for safe shutdown by UFSAR-for a fire in the Cable Spreading Room or any other Appendix R fire. There are no manual safe shutdown actions requiring access to this area. The fans are not safety related, are not credited for Appendix R safe shutdown and therefore have no License Renewal function (refer to PID CBA-LR20303 location G
| |
| -5 and H-5). USFAR Section 9.4.9.1 provides a description of the cable spreading room ventilation.
| |
| Based on its review, the staff finds the applicant's response acceptable because the manual smoke ventilation system in question is not in
| |
| -scope for license renewal and is not credited with achieving safe
| |
| -shutdown in the event of a fire. Although the CSR smoke ventilation system is addressed in NUREG
| |
| -0896, the system in question is not required in Appendix R for achieving safe
| |
| -shutdown in the event of a fire.
| |
| In the original SER, NUREG
| |
| -0896, the NRC reviewed the CSR smoke ventilation system because the licensee provided system description in the incoming UFSAR, but the licensee has not credited this system in the fire protection program. The manual smoke removal system in question is for loss of prevention purposes only.
| |
| The staff confirmed that the applicant correctly excluded the above smoke ventilation system from scope of license renewal and subject to an AMR. Therefore, the staff's concern described in the RAI 2.3.3.15
| |
| -4 is resolved.
| |
| In RAI 2.3.3.15
| |
| -5, dated November 18, 2010 (ADAMS Accession No. ML103090308), the staff stated that Section 9.5.1.6, "Fire Protection of Specific Plant Areas," of the Seabrook SER (NUREG-0896), dated March 1983, on page 9
| |
| -53, "Switchgear Rooms," states that "-[t]he Division I and Division II switchgear rooms are separated from each other and from other plant areas by 3
| |
| -hour-fire-rated wall and floor/ceiling assemblies. Automatic fire detection is provided by ionization smoke detectors. Manual protection is provided by standpipe and hose stations and portable extinguishers-" LRA Section 2.3.3.15 did not discuss scoping and screening results of Division I and Division II switchgear rooms' standpipe and hose stations.
| |
| The staff requested that the applicant verify if the Division I and Division II switchgear rooms' standpipe and hose stations are in the scope of license renewal, in accordance with 10 CFR 54.4(a), and subject to an AMR, in accordance with 10 CFR 54.21(a)(1). If the Division I and Division II switchgear rooms' standpipe and hose stations are excluded from the scope of license renewal and not subject to an AMR, the staff requested that the applicant justify the exclusion.
| |
| In a letter dated December 3, 2010 (ADAMS Accession No. ML103400259), the applicant responded to RAI 2.3.3.15
| |
| -5 by stating the following:
| |
| The standpipes and valves for the hose stations for extinguishing a fire in the Division I and Division II switchgear rooms are in scope of license renewal and are subject to an AMR in accordance with 10 CFR 54.21(a)(1). The switch gear rooms do not contain any fire protection piping. The hose stations referred to are located in the turbine building (see PID FP-LR20270 Location E 1-FP-Structures and Components Subject to Aging Management Review 2-70 R-8-A) and the south stairwell of the control building (see PID FP-LR20268 Location F
| |
| -7 for 1-FP-R-30). The hose stations reels and hoses for 1
| |
| -FP-R-8-A and 1-FP-R-30 are in scope for license renewal. The reels are subject to an AMR in accordance with 10 CFR 54.21(a)(1). The fire hoses are classified as consumables and are replaced on condition, as described on page 2.1
| |
| -24 of the LRA.
| |
| Based on its review, the staff finds the applicant's response, as clarified to include verification of the referenced discussion on page 2.1
| |
| -24 of the LRA, acceptable because it indicated that the standpipe and hose stations in question have been included in the scope of license renewal and are subject to an AMR. Further, the applicant indicated that the fire hoses are classified as consumables and are replaced on condition. Therefore, the staff's concern described in RAI 2.3.3.15
| |
| -5 is resolved.
| |
| In RAI 2.3.3.15
| |
| -6, dated November 18, 2010 (ADAMS Accession No. ML103090308), the staff stated that Section 9.5.1.6, "Fire Protection of Specific Plant Areas," of the Seabrook SER (NUREG-0896), dated March 1983, on page 9
| |
| -53, "Safety
| |
| -Related Battery Rooms," states that "-[h]ose stations and portable fire extinguishers are available in the areas for fire manual suppression-" LRA Section 2.3.3.15 did not discuss scoping and screening results of safety
| |
| -related battery rooms' hose stations.
| |
| The staff requested that the applicant verify if the safety
| |
| -related battery rooms' hose stations are in the scope of license renewal, in accordance with 10 CFR 54.4(a), and subject to an AMR, in accordance with 10 CFR 54.21(a)(1). If safety
| |
| -related battery rooms' hose stations are excluded from the scope of license renewal and not subject to an AMR, the staff requested that the applicant justify the exclusion. In a letter dated December 3, 2010 (ADAMS Accession No. ML103400259), the applicant responded to RAI 2.3.3.15
| |
| -6 by stating the following:
| |
| The standpipes and valves for the hose stations for the safety related battery rooms are in scope of license renewal and are subject to an AMR in accordance with 10 CFR 54.21(a)(1). The battery rooms do not contain any fire protection piping. The hose stations referred to are located in the turbine building (see PID FP-LR20270 Location E
| |
| -12 1-FP-R-8-A) and the south stairwell of the control building (see PID FP-LR20268 Location F
| |
| -7 for 1-FP-R-30). The hose stations reels and hoses for 1
| |
| -FP-R-8-A and 1-FP-R-30 are in scope for license renewal. The reels are subject to an AMR in accordance with 10 CFR 54.21(a)(1). The fire hoses are classified as consumables and are replaced on condition, as described on page 2.1
| |
| -24 of the LRA.
| |
| The staff reviewed the applicant's response to RAI 2.3.3.15
| |
| -6, including verification of the referenced discussion on page 2.1
| |
| -24, which confirmed that the standpipe and hose stations in question have been included in the scope of license renewal and are subject to an AMR. Further, the applicant indicated that the fire hoses are classified as consumables and are replaced on condition. Therefore, the staff's concern described in RAI 2.3.3.15
| |
| -6 is resolved.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-71 In RAI 2.3.3.15
| |
| -7, dated November 18, 2010 (ADAMS Accession No. ML103090308), the staff stated that Section 9.5.1.6, "Fire Protection of Specific Plant Areas," of the Seabrook SER (NUR EG-0896), dated March 1983, on page 9
| |
| -53, "Emergency Diesel Generator Rooms," states that "-[t]he floor trench containing fuel oil piping in each diesel generator room is provided with an automatic deluge system to combat a fire in the trench." LRA Section 2.3.3.15 did not discuss scoping and screening results of the automatic deluge system in the diesel generator room floor trench containing fuel oil piping.
| |
| The staff requested that the applicant verify if the automatic deluge system in question is in t he scope of license renewal, in accordance with 10 CFR 54.4(a), and subject to an AMR, in accordance with 10 CFR 54.21(a)(1). If the automatic deluge system is excluded from the scope of license renewal and not subject to an AMR, the staff requested that the applicant justify the exclusion.
| |
| In a letter dated December 3, 2010 (ADAMS Accession No. ML103400259), the applicant responded to RAI 2.3.3.15
| |
| -7 by stating the following:
| |
| The floor trench containing fuel oil piping in each diesel generator room with an automatic deluge system is in scope of license renewal and is subject to an AMR in accordance with 10 CFR 54.21 (a)(1). See LRA Page 2.3
| |
| -148 (for the in scope boundary description) and PID FP-LR20271 location H
| |
| -10 and F-10 for sprinkler zones 1A
| |
| -2 and 1B-2. The staff reviewed the applicant response to RAI 2.3.3.15
| |
| -7, including verification of the referenced discussion on page 2.3
| |
| -148, which confirmed that the automatic deluge system associated with diesel generator rooms' floor trench containing fuel oil piping has been included in the scope of license renewal and is subject to an AMR. Therefore, the staff's concern described in RAI 2.3.3.15
| |
| -7 is resolved.
| |
| In RAI 2.3.3.15
| |
| -8, dated November 18, 2010 (ADAMS Accession No. ML103090308), the staff stated that Tables 2.3.3
| |
| -22 and 3.3.2
| |
| -22 of the LRA do not include the following fire protection components:
| |
| * fire hose stations, fire hose connections, and hose racks
| |
| * yard fire hydrants
| |
| * strainers
| |
| * tubing
| |
| * spray nozzles
| |
| * diesel fire pump engine
| |
| -heat exchanger bonnet, shell, tubes, and exhaust silencer
| |
| * floor drains for fire water
| |
| * dikes and curbs for oil spill confinement The staff requested that the applicant verify if the fire protection components listed above are in the scope of license renewal, in accordance with 10 CFR 54.4(a), and subject to an AMR, in accordance with 10 CFR 54.21(a)(1). If they are excluded from the scope of license renewal and are not subject to an AMR, the staff requested that the applicant justify the exclusion.
| |
| In a letter dated December 3, 2010 (ADAMS Accession No. ML103400259), the applicant responded to RAI 2.3.3.15
| |
| -8 by stating the following:
| |
| Structures and Components Subject to Aging Management Review 2-72 License renewal drawing (PID [license renewal] Notes 1) provides a description of the component types and a correlation that shows the component grouping they are evaluated as.
| |
| Fire protection system components subject to age management review are listed in Table 2.3.3
| |
| -15 (page 2.3
| |
| -151) and a summary of the aging management evaluation for the fire protection system is provided in Table 3.3.2-15 (page 3.3
| |
| -300) of the LRA. Fire hose stations include the fire hose, the fire hose racks (evaluated as supports) and the fire hose connections.
| |
| * The fire hose racks (supports) are evaluated under supports in the LRA Section 2.4.6 and are in scope of License Renewal and subject to an AMR in accordance with 10 CFR 54.21(a)(1).
| |
| * Fire hoses are within the scope of License Renewal, but are not subject to aging management because they are replaced based on condition. These components are periodically inspected in accordance with National Fire Protection Association (NFPA) standards. Fire hoses are considered consumables. See Section 2.3.1 (page 2.1-24) in the LRA.
| |
| * Fire hose connections are in scope of license renewal and are evaluated as pipe and fittings and are subject to an AMR in accordance with 10 CFR 54.21(a)(1). See Table 3.3.2
| |
| -15 (page 3.3
| |
| -300) in the LRA.
| |
| * Yard fire hydrants in the scope of License Renewal are designated FH on the license renewal prints and are evaluated as valves in Table 3.3.2
| |
| -15 on page 3.3
| |
| -300 of the LRA and are subject to an AMR in accordance with 10 CFR 54.21(a)(1).
| |
| * Strainers in scope of License Renewal are evaluated as filter elements and filter housings in Table 3.3.2
| |
| -15 on page 3.3
| |
| -300 of the LRA and are subject to an AMR in accordance with 10 CFR 54.21(a)(1).
| |
| * Tubing in scope of License Renewal is evaluated as pipe in Table 3.3.2
| |
| -15 (page 3.3-300) of the LRA and is subject to an AMR in accordance with 10 CFR 54.21(a)(1).
| |
| * Spray nozzles in the scope of License Renewal are evaluated as sprinklers in Table 3.3.2-15 (page 3.3
| |
| -300) of the LRA and are subject to an AMR in accordance with 10 CFR 54.21(a)(1).
| |
| * The diesel fire pump engine heat exchanger including the bonnet, shell, and tubes, are an integral part of the diesel fire pump engine and were evaluated as a unit. The diesel fire pump engine is screened out as an active component per NEI 95
| |
| -10 Appendix B.
| |
| * The diesel fire pump exhaust silencer is evaluated under pipe and fittings and is subject to an AMR in accordance with 10 CFR 54.21(a)(1). See Table 3.3.2
| |
| -15 (pages 3.3
| |
| -308 and 309). The summary of the aging management review for the internal surface is provided on page 3.3
| |
| -309, Piping and Fittings, Pressure Boundary, Steel, Diesel Exhaust (Internal). The summary of the aging management review for the external surface is provided on page 3.3
| |
| -308, Piping and Fittings.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-73
| |
| * Floor drains for fire water are in scope of License Renewal and evaluated in section 2.3.3.45, "Waste Processing Liquid Drains System," (page 2.3
| |
| -269) and section 2.3.3.26, "Plant Floor Drain System," (page 2.3
| |
| -191) of the LRA. These floor drains are subject to an AMR in accordance with 10 CFR 54.21(a)(1).
| |
| * The dikes and curbs' for oil spill confinement in scope of License Renewal are evaluated under structures as a commodity under Concrete in Tables 3.5.2
| |
| -2 and 3.5.2-5. These dikes and curbs are subject to an AMR in accordance with 10 CFR 54.21(a)(1).
| |
| In reviewing its response to RAI 2.2.3.15
| |
| -8, the staff found that the applicant had addressed and resolved each item in the RAI, as discussed below.
| |
| Fire hose stations, including fire hose racks and fire hose connections, are in the scope of license renewal and subject to an AMR. Fire hose racks are included under line item "Supports," which are in the scope of license renewal, subject to an AMR, and listed in LRA Section 2.4.6. Fire hose connections are evaluated under line item description "Piping and Fitting," in LRA Table 3.3.2
| |
| -15. Fire hoses are within the scope of license renewal but are not subject to an AMR because they are consumable. The applicant stated that it considers yard fire hydrants in the line item "Valves," in Table 3.3.2-15, and they are subject to an AMR.
| |
| Tubing is also evaluated under line item description "Piping and Fitting," in LRA Table 3.3.2
| |
| -15. In addition, the applicant addressed strainers under line items "Filter Elements" and "Filter Housings," in LRA Table 3.3.2
| |
| -15. Furthermore, in its response, the applicant confirmed that spray nozzles are included under line item "Sprinklers," which are in the scope of license renewal, subject to an AMR, and listed in Table 3.3.2
| |
| -15. The applicant stated that fire pump exhaust silencer is evaluated under line item description "Piping and Fitting," in LRA Table 3.3.2
| |
| -15. Further, the applicant considered heat exchanger bonnet, shell, and tubes to be active components as a part of the diesel fire pump engine; they are not subject to an AMR.
| |
| The floor drains for fire water are included under "Plant Floor Drain System" in LRA Section 2.3.3.26 and "Waste Processing Liquid Drains System" in Section 2.3.3.45; these are in the scope of license renewal and subject to an AMR. The applicant considered curbs for oil spill confinement under structural commodities as "Concrete," listed in LRA Tables 3.5.2
| |
| -2 and 3.5.2-5. By letter dated September 18, 2012 (ADAMS Accession No. ML12268A171), the applicant submitted the second annual update to the LRA, identifying changes made to the CLB that materially affect the contents of the LRA. The applicant amended LRA Section 2.3.3.15, "Fire Protection System," and Tables 2.3.3.15 and 3.3.2.15 to add components, a valve, and a flow
| |
| -restricting orifice in the portion of the water supply system in the Control Building and Diesel Generator Building. The applicant stated that, to limit break flow in the event of a fire protection piping rupture, a normally closed valve is installed in the header supplying the Control Building and Diesel Generator Building hose reels. A bypass line with a flow
| |
| -restricting orifice is installed around this valve to limit the flow from a rupture of downstream piping but still allow adequate flow to support the use of downstream hose reels. The valve is installed to allow additional flow to the downstream hose reels at the firefighters' discretion. The valve, bypass line, and orifice are installed in the Radiological Controlled Area Walkway.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-74 The staff reviewed the applicant's revisions, noted above, and found that the additional fire protection components installed will prevent or mitigate internal flooding in the event of fire protection system pressure boundary failure and still maintain adequate water flow for manual firefighting. The staff concluded that the applicant has appropriately identified additional components within the scope of license renewal, consistent with the staff's reviewing criteria in the SRP-LR. 2.3.3.15.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI responses, and license renewal boundary drawings to determine whether the applicant had identified all components within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all components subject to an AMR. On the basis of its review, the staff concludes the applicant appropriately identified the fire protection system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
| |
| 2.3.3.16 Fuel Handling System 2.3.3.16.1 Summary of Technical Information in the Application The new fuel storage facilities are located within the fuel storage building and are designed to facilitate the safe handling, inspection, and storage of new fuel assemblies and control rods. Space is provided for handling and storage of 90 new fuel assemblies, which is equal to a core load plus 25 spare assemblies.
| |
| The fuel transfer system includes an underwater, electric
| |
| -motor-driven, transfer car that runs on tracks extending from the containment refueling canal through the transfer tube and into the fuel storage building refueling canal. A hydraulically actuated lifting arm is on each end of the transfer tube. The fuel container in the refueling canal receives a fuel assembly in the vertical position from the refueling machine. The fuel assembly is then lowered to a horizontal position for passage through the transfer tube. After passing through the tube, the fuel assembly is raised to a vertical position for removal by a tool suspended from the spent fuel pool bridge and hoist in the fuel storage building refueling canal. A system of lifting arms and hydraulic cylinders is used to raise and lower the fuel containers containing the fuel assembly. The cylinders are powered by hydraulic pumping units and controlled by electronic consoles. The pumping units and consoles (one each in the containment and fuel storage building, designated 1
| |
| -FH-RE-44 and 1-FH-RE-45, respectively) are located on the operating deck of each building. The spent fuel pool bridge and hoist then moves to a storage loading position and places the spent fuel assembly in the spent fuel storage racks.
| |
| During reactor operation, the transfer car is stored in the fuel storage building refueling canal. The quick closure hatch is engaged closed on the containment refueling canal end of the transfer tube to seal the reactor containment. The terminus of the tube in the fuel storage building is closed by a valve.
| |
| 2.3.3.16.2 Conclusion
| |
| | |
| Structures and Components Subject to Aging Management Review 2-75 Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant appropriately identified the fuel handling system components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the fuel handling system components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.17 Fuel Oil System 2.3.3.17.1 Summary of Technical Information in the Application The fuel oil system provides fuel to the two diesel
| |
| -driven fire pumps FP-P-20A and 1-FP-P-20B. There are two fuel tanks, each dedicated to a diesel
| |
| -driven fire pump.
| |
| 2.3.3.17.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the fuel oil system components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the fuel oil system components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.18 Fuel Storage Building Air Handling System 2.3.3.18.1 Summary of Technical Information in the Application The normal heating and ventilation subsystem is comprised of filters, dual purpose chilled water cooling and hot water heating coils for summer cooling or winter heating, supply air fans, chillers, and a ducted distribution system with parallel
| |
| -path supply dampers, which are a part of the primary auxiliary building ventilation system. A hot water unit heater system, which is supplied with hot water from the primary auxiliary building HW system, is also provided. The system is designed to maintain inside design temperatures suitable for equipment and personnel. The ventilation function is provided by the fuel storage building ventilation system. The heating function is provided by the HW system and is evaluated separately.
| |
| The normal heating and ventilation subsystem employs two slotted exhaust intake hood s designed to sweep the pool surface in order to capture the dilute vapors emanating from the spent fuel pool. The entrained air and vapor are ducted to a vane axial fan, normal ventilation exhaust air isolation damper and from there to the unit plant vent. Two basic modes of air handling are available, as discussed below. For all modes, the operation of the mechanical equipment is controlled and monitored from the plant unit control room. Normal Once
| |
| -Through Supply Exhaust Ventilation Mode. During normal operation, filtered outside air is circulated through the fuel storage building by the normal ventilation system, with the exhaust air discharged from the building via the unit plant vent. Filtering of the exhaust air is not normally performed.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-76 Fuel Handling Mode. The fuel handling mode is used any time irradiated fuel not in a sealed cask is handled. In the fuel handling mode of operation, the normal building exhaust system is isolated prior to initiation of fuel handling operations by closing the normal exhaust isolation damper and stopping the normal exhaust fan. The fuel storage building is maintained at a negative pressure of 0.25
| |
| -in. water gauge (w.g.) or more (negative). This is achieved by exhausting air from the building at a higher rate than directly supplied from the primary auxiliary building supply air system. Maintaining the building at a negative pressure will minimize, or eliminate, the leakage of radioactive material to the environment in the event of an accident. The exhaust filter trains are redundant, with one unit required to operate in the event of an accident.
| |
| The redundant filter units and their respective components are fed from independent power sources so that no single failure would prevent the obtaining and maintaining of the negative pressure. The static pressure control for the parallel supply system dampers are provided with manual override provisions to allow the operator to control the damper position and the building pressure if required.
| |
| The fuel storage building emergency air cleaning system is a seismic Category I, safety Class 3 system.
| |
| 2.3.3.18.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the fuel storage building air handling system components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the fuel storage building air handling system components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.19 Hot Water Heating System 2.3.3.19.1 Summary of Technical Information in the Application The hot water heating (HW) system includes the station designated hot water supply and hot water return systems. In addition to providing heating to buildings not within the license renewal boundary, such as the administration building, turbine building, and waste process building, the HW system provides the functions described below.
| |
| Fuel storage building normal heating is comprised of filters, dual purpose chilled water cooling and hot water heating coils for summer cooling or winter heating, supply air fans, chillers, and a ducted distribution system with parallel path supply dampers, which are a part of the primary auxiliary building ventilation system. A hot water unit heater system, which is supplied with hot water from the primary auxiliary building HW system, is also provided. The system is designed to maintain inside design temperatures suitable for equipment and personnel.
| |
| Primary auxiliary building heating is maintained in the winter by heating the outside air with a bank of dual purpose chilled water cooling and hot water heating coils. The water temperature for the main hot water heating coils is controlled by thermostats mounted in the primary auxiliary building. The heating coils are supplied with hot water and glycol from a closed loop parallel pump circulating system using a common steam and hot water converter. The closed Structures and Components Subject to Aging Management Review 2-77 loop circulating system for the main heating coils comprises three pumps, one for each bank of heating coils and one reserve pump, each manually controlled locally. Each pump once started runs continuously. Certain rooms contain a pair, or pairs, of unit heaters connected to thermostats located in the room that will operate the unit heater fans to maintain the room temperature above minimum design requirements. The unit heaters are supplied with hot water and glycol from a closed loop system using the same steam and hot water converter as the primary auxiliary building main hot water heating coils. One centrifugal pump provides circulating water to all of the unit heaters within each room. The pump is started manually from the main control panel and runs continuously.
| |
| Heating for the diesel generator building is provided by hot water unit heaters. Four unit heaters are located in each diesel generator area. Each of the two area heating systems is provided with hot water from the hot water and steam converter. Three hot water circulating pumps, one for each area and the third, a standby for both, are energized from the local control panel and will run until the operator manually stops them. Operation of the unit heaters is thermostatically controlled. The hot water heating piping is contained or shielded where it passes over safety
| |
| -related electrical equipment. Cable spreading room ventilation system supply air is reheated, when required, by a hot water heating coil in the supply ductwork to offset building heat losses. The cable spreading room ventilating system obtains makeup air and hot water for heating from the switchgear area and battery rooms heating and ventilating system. In the winter the 4
| |
| -kilovolt (kV) switchgear areas, cable spreading area, and the electrical tunnel area air is recirculated and mixed with preheated outside air, as necessary, for makeup and to maintain the inside design temperature.
| |
| The 4-kV switchgear areas and battery rooms have two ventilation equipment rooms, one for each train. The equipment rooms serve as a return air and makeup air mixing plenum. The heat required to offset building heat loss from the switchgear areas, battery rooms, and electrical tunnels is supplied by hot water unit heaters located in the equipment rooms. Water line breaks or hot water system failures will not affect the operation of the switchgear areas or battery rooms.
| |
| The emergency feedwater water pump house heating system is designed to maintain the pump house at or above 50° F when the outside temperature is 0° F or above. The heating system consists of a shared steam and hot water converter, two 100
| |
| -percent capacity pumps, a piping system, and two 100-percent capacity unit heaters. The heating medium is a mixture of water and glycol in a closed loop circulating system. The glycol acts to prevent freezing should the steam supply, electrical power source, or a pump or driver fail. Each unit heater is controlled by its own room thermostat.
| |
| The pump room area of the service water pump house is maintained at 50° F or above when the outside temperature is 0° F or above by a HW system using unit heaters. Hot water is pumped through the unit heaters from a steam
| |
| -to-hot-water heat exchanger located in the adjacent circulating water pump house. The heating system is not required to maintain operation of the service water pumping equipment.
| |
| 2.3.3.19.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.19, UFSAR Section 9.4, and the license renewal boundary drawings using the evaluation methodology described in SER Section 2.3 and the Structures and Components Subject to Aging Management Review 2-78 guidance in SRP
| |
| -LR Section 2.3. The staff's review identified areas in which additional information was required to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAIs, as discussed below.
| |
| In RAI 2.3.3.19
| |
| -01, dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff noted on LRA drawing PID HW-LR20051 that the applicant depicts the HW expansion tanks within the scope of license renewal under 10 CFR 54.4(a)(2). The 1/2 in. vent lines attached to the expansion tanks, at locations G
| |
| -11 and G-12, are shown not within scope of license renewal. The applicant was asked to justify the exclusion of the 1/2 in. vent lines from the scope of license renewal.
| |
| In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant clarified that the 1/2 in. lines are within the scope of license renewal under 10 CFR 54.4(a)(2). The applicant also described the 1/2 in. lines as 1/2 in. carbon steel piping with threaded plugs at the end. Based on its review, the staff finds the applicant's response to RAI 2.3.3.19
| |
| -01 acceptable because the staff confirmed that the 1/2 in. lines are already included within the scope of license renewal under 10 CFR 54.4(a)(2). Therefore, the staff's concern described in RAI 2.3.3.19
| |
| -01 is resolved.
| |
| In RAI 2.3.3.19
| |
| -02, dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff noted on LRA drawing PID HW-LR20056, at location G
| |
| -11, that the applicant depicted the make-up tank as not being within the scope of license renewal. However, the make
| |
| -up tank is connected to nonsafety
| |
| -related piping that is included within the scope of license renewal under 10 CFR 54.4(a)(2). The applicant was asked to justify its exclusion of the make
| |
| -up tank from the scope of license renewal.
| |
| In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant stated that the make-up tank is within scope of license renewal under 10 CFR 54.4(a)(2). The applicant indicated that the LRA drawing PID HW-LR20056 erroneously depicted the make
| |
| -up tank excluded from scope of license renewal.
| |
| Based on its review, the staff finds the applicant's response to RAI 2.3.3.19
| |
| -02 acceptable because the applicant clarified that the make
| |
| -up tank is within the scope of license renewal under 10 CFR 54.4(a)(2). Therefore, the staff's concern described in RAI 2.3.3.19
| |
| -02 is resolved.
| |
| 2.3.3.19.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI responses, and license renewal boundary drawings to determine whether the applicant had identified all components within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all components subject to an AMR. On the basis of its review, the staff concludes the applicant appropriately identified the HW system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
| |
| | |
| Structures and Components Subject to Aging Management Review 2-79 2.3.3.20 Instrument Air System 2.3.3.20.1 Summary of Technical Information in the Application The plant's compressed air function is provided by the service air and the instrument air systems. The components from the service air system have been incorporated with the instrument air system, and the containment compressed air system was evaluated with the instrument air system components.
| |
| The compressed air system consists of two subsystems
| |
| -the plant compressed air system and the containment compressed air system. Each subsystem employs redundant, oil
| |
| -free compressors with associated filters, after coolers, moisture separators, air dryers, receivers, and operating controls.
| |
| 2.3.3.20.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.20, UFSAR Section 9.3.1, UFSAR Tables 7.5
| |
| -1 and 6.2-83, and the license renewal boundary drawings using the evaluation methodology described in SER Section 2.3 and the guidance in SRP
| |
| -LR Section 2.3. The staff's review identified areas in which additional information was required to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAIs, as discussed below.
| |
| In RAI 2.3.3.20
| |
| -01, dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff noted on LRA drawing PID IA-LR20637 that the applicant depicts 1
| |
| -in. piping within scope of license renewal under 10 CFR 54.4(a)(3). However, on the continuation LRA drawing PID IA-LR20638, the applicant depicts the 1
| |
| -in. piping as not being within scope of license renewal. The applicant was asked to justify the exclusion of the 1
| |
| -in. piping from the scope of license renewal on the LRA drawing PID IA-LR20638. In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant stated that most of the loop B piping is excluded from scope of license renewal due to check valves that prevent backflow into the loop A piping. The applicant referenced that license renewal Note 4 on both LRA drawings state "[c]heck valve prevents back flow into other air trains." However, the applicant indicated that there is also a backflow check valve on the 1
| |
| -in. piping between the air filter and valve V
| |
| -457, but it was not depicted in LRA drawing PID IA-LR20638 with license renewal Note 4. The applicant clarified that the 1
| |
| -in. piping downstream (and leading into the continuation flag for LRA drawing PID IA-LR20637) from the backflow check valve is within the scope of license renewal under 10 CFR 54.4(a)(3). The applicant also stated that LRA drawing PID IA-LR20638 erroneously depicts this portion of the 1
| |
| -in. piping as excluded from the scope of license renewal.
| |
| Based on its review, the staff finds the applicant's response to RAI 2.3.3.20
| |
| -01 acceptable because the 1-in. piping was already included within the scope of license renewal under 10 CFR 54.4(a)(3). The staff confirmed that the applicant's description of the scoping boundary of the piping on loop B is consistent with license renewal Note 4 on LRA drawing PID-1-IA-LR20638 involving check valves for the instrument air system. Therefore, the staff's concern described in RAI 2.3.3.20
| |
| -01 is resolved.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-80 In RAI 2.3.3.20
| |
| -02, dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff identified the following issues on LRA drawing PID IA-LR20643:
| |
| * At locations F
| |
| -8 and F-9, no continuation piping was identified between the check valve V-531, which is depicted within the scope of license renewal under 10 CFR 54.4(a)(1), and the seismic anchor.
| |
| * At locations E-8 and F-8, portions of 2
| |
| -in. piping near valves (V
| |
| -533 and V-535) are shown within the scope of license renewal under 10 CFR 54.4(a)(3). However, the pipe sections upstream of these valves and to the seismic anchors are shown as not within the scope of license renewal.
| |
| * At locations E
| |
| -8 and F-8, the piping associated with the seismic anchors could not be identified on the drawing.
| |
| * At location E
| |
| -8, there is a line whose beginning and end are not identified.
| |
| The applicant was asked to do the following:
| |
| * provide identification of the continuation piping that is missing between the check valve V-531 and seismic anchor at locations F
| |
| -8 and F-9
| |
| * justify excluding the continuation piping between valves V
| |
| -533 and V-535 and the seismic anchors from scope of license renewal at locations E
| |
| -8 and F-8
| |
| * identify the missing continuation piping associated with the seismic anchors at locations E-8 and F-8
| |
| * identify the line on the drawing at location E
| |
| -8 In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant provided a revised portion to LRA drawing PID IA-LR20643 to include the missing components. The components include piping downstream from check valve V
| |
| -531, ball valves (V-540, V-532, and V
| |
| -534), and piping downstream of ball valves V
| |
| -532 and V-534 up to the seismic supports. The applicant indicated that the above components were included within the scope of license renewal under 10 CFR 54.4(a)(2) and are subject to an AMR. The applicant also stated that the tailpipe, which initially appeared in the LRA drawing at location E
| |
| -8, is attached downstream from the closed ball valve V
| |
| -540 and is excluded from scope of license renewal since it is not fluid filled.
| |
| Based on its review, the staff finds the applicant's response to RAI 2.3.3.20
| |
| -02 acceptable because the applicant clarified the components that are within scope of license renewal. The staff also confirmed that the tailpipe was appropriately excluded from scope of license renewal since it does not serve an intended function beyond closed ball valve V
| |
| -540. Therefore, the staff's concern described in RAI 2.3.3.20
| |
| -02 is resolved.
| |
| In RAI 2.3.3.20
| |
| -03, dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff could not locate seismic anchors on eight nonsafety
| |
| -related lines connected to safety
| |
| -related lines in LRA drawing PID IA-LR20647. The applicant was asked to clarify the locations of the seismic anchors.
| |
| In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant stated both the safety
| |
| -related and nonsafety
| |
| -related instrument air piping in the primary Structures and Components Subject to Aging Management Review 2-81 auxiliary building are seismically supported by a series of pipe supports. Six of the nonsafety
| |
| -related lines, which consist of nonsafety
| |
| -related 1/2-in. tubing, are anchored by the associated instruments, which are rigidly mounted. The applicant also stated that the other two locations of nonsafety
| |
| -related piping are located near check valves V
| |
| -8032 and V
| |
| -8031 and do not contain seismic anchors. The applicant stated that the continued nonsafety
| |
| -related piping beyond the check valves provides structural support for the safety
| |
| -related piping to ensure that the nonsafety
| |
| -related piping loads are not transferred through the safety and nonsafety interface, as determined by its piping stress analysis.
| |
| Based on its review, the staff finds the applicant's response to RAI 2.3.3.20
| |
| -03 acceptable because the applicant explained that, based on piping stress analysis, the nonsafety
| |
| -related piping loads are not transferred through the safety and nonsafety interface. Therefore, seismic anchors are not required, and the staff's concern described in RAI 2.3.3.20
| |
| -03 is resolved.
| |
| 2.3.3.20.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI responses, and license renewal boundary drawings to determine whether the applicant had identified all components within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all components subject to an AMR. On the basis of its review, the staff concludes the applicant appropriately identified the instrument air system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
| |
| 2.3.3.21 Leak Detection System 2.3.3.21.1 Summary of Technical Information in the Application The leak detection system components monitor indications of leakage inside the containment building by the use of pressure, temperature, and level instruments.
| |
| 2.3.3.21.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the leak detection system components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the leak detection system components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.22 Mechanical Seal Supply System 2.3.3.22.1 Summary of Technical Information in the Application The mechanical seal supply system is designed to supply flushing water to the mechanical seals of the NNS class pumps of the plant. The mechanical seals are provided on these pumps so that no leakage of the process fluid occurs past the shaft into the environment. For their proper functioning, the seal faces have to be kept flushed and under a minimum pressure of 15 psig higher than the process fluid pressure on the suction side of the pump. This Structures and Components Subject to Aging Management Review 2-82 ensures the mating of the seal faces without any particulates entrapped between them and does not allow any process fluid to enter the seal cavity (or the stuffing box).
| |
| 2.3.3.22.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.22 and the license renewal boundary drawings using the evaluation methodology described in SER Section 2.3 and the guidance in SRP
| |
| -LR Section 2.3. The staff's review identified an area in which additional information was required to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAI, as discussed below.
| |
| In RAI 2.3.3.22
| |
| -01, dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff noted on drawing PID DM-LR20353, at location H
| |
| -3, that the applicant refers to license renewal Note 1, which indicates that pump SF
| |
| -P-272 is within the scope of license renewal under 10 CFR 54.4(a)(2). However, on LRA drawing PID SF-LR20484, pump SF-P-272 is not depicted as being within the scope of license renewal. The applicant was asked to clarify the scoping classification for pump SF
| |
| -P-272. In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant indicated LRA drawing PID DM-LR20353, license renewal Note 1, refers to the mechanical seal supply system piping going to the pump SF
| |
| -P-272. License renewal Note 3, on the same drawing, labeled the mechanical seal as a short
| |
| -lived item, excluding it from the scope of license renewal. The applicant also described the mechanical seal supply piping to the pump mechanical seal as stainless steel material in a treated water internal environment, which is why it was included within the scope of license renewal under 10 CFR 54.4(a)(2).
| |
| Based on its review, the staff finds the applicant's response to RAI 2.3.3.22
| |
| -01 acceptable because the applicant clarified that license renewal Note 1 in LRA drawing PID DM-LR20353 addressed the mechanical seal piping, which is already included within the scope of license renewal under 10 CFR 54.4(a)(2). Therefore, the staff's concern described in RAI 2.3.3.22
| |
| -01 is resolved.
| |
| 2.3.3.22.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI response, and license renewal boundary drawings to determine whether the applicant had identified all components within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all components subject to an AMR. On the basis of its review, the staff concludes the applicant appropriately identified the mechanical seal supply system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
| |
| 2.3.3.23 Miscellaneous Equipment 2.3.3.23.1 Summary of Technical Information in the Application Miscellaneous equipment contains the hydraulic piping and components that operate the personnel hatch doors for entry into containment. The hydraulic network equalizes air lock pressure, rotates the locking ring to the unlock position, and opens the outer door. On close Structures and Components Subject to Aging Management Review 2-83 demand, the network closes the door, closes the equalizing valve, rotates, and locks the locking ring. Similarly, a personnel air lock hydraulic reservoir inside the containment operates with a network of control valves, piping, interlock controls, and actuating pistons. The hydraulic network equalizes air lock pressure, rotates the locking ring to the unlock position, and opens the inner door. On close demand, the network closes the door, closes the equalizing valve, then rotates and locks the locking ring.
| |
| 2.3.3.23.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the miscellaneous equipment mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the miscellaneous equipment mechanical components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.24 Nitrogen Gas System 2.3.3.24.1 Summary of Technical Information in the Application The function of the nitrogen gas system is to supply nitrogen at controlled pressures to various locations in the unit for the following reasons:
| |
| * pressurizing the SI accumulators
| |
| * inerting and purging systems
| |
| * use as a cover gas
| |
| * preventing corrosion during wet and dry lay
| |
| -up of components The nitrogen gas system supplies the following major systems and components:
| |
| * SI accumulators
| |
| * waste processing liquid drains system's reactor coolant drain tank
| |
| * RCS primary relief tank
| |
| * waste gas (WG) system
| |
| * vent gas (VG) system
| |
| * release recovery system tanks
| |
| * CS's volume control tank and letdown degasifier
| |
| * resin sluice system tanks
| |
| * reactor makeup water tank
| |
| * main steam system
| |
| * boron recovery system's primary drain tanks and degasifier
| |
| * steam generator blowdown system 2.3.3.24.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the nitrogen gas system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant Structures and Components Subject to Aging Management Review 2-84 adequately identified the nitrogen gas system mechanical components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.25 Oil Collection for Reactor Coolant Pumps System 2.3.3.25.1 Summary of Technical Information in the Application The seismically
| |
| -designed lube oil collection system for the four RCPs has been designed with two collection tanks, with two pumps draining to each tank. Each of the two tanks has been sized to contain 125 percent of the oil inventory of one pump. A seismically designed dike has been provided around each tank. Each tank, in combination with its associated dike, has been sized to contain the entire inventory of two pumps. The tanks and the dikes have been located so that the excess oil does not present a fire hazard to any safety
| |
| -related equipment. Additionally, there is no ignition source near the diked area.
| |
| 2.3.3.25.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the oil collection for RCPs system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the oil collection for RCPs system mechanical components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.26 Plant Floor Drain System 2.3.3.26.1 Summary of Technical Information in the Application The floor drains in this system are located outside any area with a potential for contamination.
| |
| The plant floor drain system is located in those areas where automatic sprinkler and spray systems are installed. These drains are sized to pass the expected flows resulting from automatic system actuation, as well as that produced by manual hose application if employed. In areas where hand hose lines are the only water sources used to combat a fire, drains are provided if accumulation of fire
| |
| -fighting water could result in unacceptable damage to safety
| |
| -related equipment in the area. In such areas, the operator can use the hose to control the quantity of drain water to avoid unacceptable damage to equipment.
| |
| Drainage within the diesel generator building is designed to prevent the spread of fire from one area to another. Other areas with combustible liquids have normally closed shut
| |
| -off valves in the drain lines or drain directly to the oil and water separation vault. The electrical tunnels contain no sources of floodwater other than the fire protection system piping. The fire protection system piping consists of zoned reaction dry pipe systems with the zone valves located outside the electrical tunnel areas.
| |
| The individual fire protection system zones will be actuated by ionization fire detectors. Fire detectors are provided in the areas zoned to provide local indication and an audible and visual alarm in the control room and the guardhouse. Water from the fire protection system will be drained from the tunnel zones to a sump outside the electrical tunnel areas (located in the emergency feedwater pump house). Redundant pumps have been installed in the sump to pump the water collected from the tunnel to the storm drain system (not within the scope of license renewal).
| |
| | |
| Structures and Components Subject to Aging Management Review 2-85 Failure of a circulating water system expansion joint in the turbine building will flood the ground floor pit east of the condensers in the turbine building. Assuming the worst possible failure to be a 2-in. gap all around, the pit would fill up in about 3 minutes, unless prompt action by the operator is taken. There are two level switches (1
| |
| -DR-LSH-5984 and 5985) in the condenser pit that provide sequential alarms in the control room to warn the operator of the flooded condition. No loss of offsite power is induced by a failure of this equipment provided operator action is taken within 22.2 minutes to mitigate the consequences of the flood.
| |
| 2.3.3.26.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.26 and the license renewal boundary drawings using the evaluation methodology described in SER Section 2.3 and the guidance in SRP
| |
| -LR Section 2.3. The staff's review identified an area in which additional information was required to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAI, as discussed below.
| |
| In RAI 2.3.3.26
| |
| -01, dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff noted LRA Section 2.3.3.26 provides a UFSAR reference of Appendix A, Section F.3, page 41. However, the reference could not be located in the UFSAR that was submitted to the staff with the LRA. The applicant was asked to provide the UFSAR reference for Appendix A, Section F.3, page 41, so that the staff can confirm that the components included in the plant floor drain system have been appropriately identified and included within the scope of license renewal.
| |
| In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant provided a copy of the UFSAR reference for Appendix A, Section F.3, page 41. UFSAR Section 9.5.1, "Fire Protection System," references the supplemental report, "Evaluation and Comparison to BTP APCSB 9.5
| |
| -1, Appendix A Report," which describes the floor drain system components used for fire protection.
| |
| Based on its review, the staff finds the applicant's response to RAI 2.3.3.26
| |
| -01 acceptable because the staff reviewed the supplemental report to confirm the plant floor drain system components that are within the scope of license renewal. Therefore, the staff's concern described in RAI 2.3.3.26
| |
| -01 is resolved.
| |
| 2.3.3.26.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI response, and license renewal boundary drawings to determine whether the applicant had identified all components within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all components subject to an AMR. On the basis of its review, the staff concludes the applicant appropriately identified the plant floor drain system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the mechanical components subject to an AMR in accordance with th e requirements stated in 10 CFR 54.21(a)(1).
| |
| 2.3.3.27 Potable Water System 2.3.3.27.1 Summary of Technical Information in the Application
| |
| | |
| Structures and Components Subject to Aging Management Review 2-86 Potable water received from the Town of Seabrook water main is metered at the fire pump house and then piped to the fire water storage tanks and the plant distribution system. The fire protection tank fill line is equipped with a backflow preventer. Chlorine injection is provided for control of biological growths in the fire protection tanks and associated piping. The water treatment makeup system uses the undedicated 200,000
| |
| -gal. capacity of each fire water storage tank as its source of makeup water. The system is not safety related and is not relied upon to perform a safety
| |
| -related function.
| |
| The distribution system consists of branch mains to the various personnel areas
| |
| -the service water cooling tower fill, the demineralized water makeup system, and the fire water storage tank fills. Branch headers and branches lead to the various fixtures. Drinking fountains, eye and face wash fountains, lavatories, urinals, water closets, showers, safety showers, water coolers, water heaters, and special fixtures are provided according to occupancy. Connections are provided to kitchen, laboratory, and similar equipment requiring potable water. The branch main to personnel areas is equipped with a backflow preventer and hose bib vacuum breakers to prevent backflow or siphoning.
| |
| 2.3.3.27.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.27 and the license renewal boundary drawings using the evaluation methodology described in SER Section 2.3 and the guidance in SRP
| |
| -LR Section 2.3. The staff's review identified areas in which additional information was required to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.
| |
| In RAI 2.3.3.27
| |
| -01, dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff noted on LRA drawing PID CBA-LR20303, at locations B
| |
| -11 and B-12, that the applicant depicts sections of safety
| |
| -related 12
| |
| -in. piping directly connected to nonsafety
| |
| -related 11/2
| |
| -in. piping passing through gate valves V
| |
| -7 and V-8. The nonsafety
| |
| -related 11/2
| |
| -in. lines continue through check valve V
| |
| -3 to the storm sewer. The seismic anchors could not be located for these lines through valves V
| |
| -7 and V-8 beyond the safety and nonsafety interface. The applicant was asked to provide the seismic anchor locations for the 11/2
| |
| -in. lines.
| |
| In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant stated that nonsafety
| |
| -related 11/2
| |
| -in. piping is Seismic Category I and that the Seabrook design review indicated the smaller 11/2
| |
| -in. nominal diameter piping would not impose loads on the larger safety
| |
| -related piping. The applicant referenced UFSAR 3.7(B).3.3a, in which the branch connections are decoupled from the main runs when the ratio of the branch to run section is equal to or less than 0.05. The applicant indicated that the ratio of the branch (the nonsafety
| |
| -related 11/2
| |
| -in. piping) to run section (12
| |
| -in. safety
| |
| -related piping) moduli is 0.003, which is less than 0.05. Thus, the applicant determined that seismic anchors were not required beyond the safety and nonsafety interface.
| |
| Based on its review, the staff finds the applicant's response to RAI 2.3.3.27
| |
| -01 acceptable because the staff confirmed that the applicant's assessment of the nonsafety
| |
| -related 11/2
| |
| -in. piping effects onto the safety
| |
| -related 12
| |
| -in. piping is consistent with the piping decoupling criteria, as indicated in the UFSAR, which negated the purpose for establishing seismic anchors on the 11/2
| |
| -in. piping. Therefore, the staff's concern described in RAI 2.3.3.27
| |
| -01 is resolved.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-87 In RAI 2.3.3.27
| |
| -02, dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff noted on LRA drawing PID DF-LR20200, at location H
| |
| -7, that the applicant depicts a section of 4-in. piping within the scope of license renewal under 10 CFR 54.4(a)(2). The 4
| |
| - in. piping continues to LRA drawing PID SD-LR20402, at location F
| |
| -7, where it is no longer depicted within the scope of license renewal. The applicant was asked to justify the exclusion of the portion of the 4
| |
| -in. piping from the scope of license renewal on LRA drawing PID SD-LR20402. In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant stated that the 4
| |
| -in. piping is within the scope of license renewal under 10 CFR 54.4 (a)(2) up to the point where it exits the east main steam and feedwater pipe chase. The applicant also stated that LRA drawing PID-1-SD-LR20402 erroneously depicted the 4
| |
| -in. piping as being excluded from the scope of license renewal.
| |
| Based on its review, the staff finds the applicant's response to RAI 2.3.3.27
| |
| -02 acceptable because the 4
| |
| -in. piping on LRA drawing PID SD-LR20402 is within the scope of license renewal and was erroneously depicted as not within the scope of license renewal under 10 CFR 54.4(a)(2). Therefore, the staff's concern described in RAI 2.3.3.27
| |
| -02 is resolved.
| |
| 2.3.3.27.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI responses, and license renewal boundary drawings to determine whether the applicant had identified all components within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all components subject to an AMR. On the basis of its review, the staff concludes the applicant appropriately identified the potable water system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
| |
| 2.3.3.28 Primary Auxiliary Building Air Handling System 2.3.3.28.1 Summary of Technical Information in the Application The function of the normal heating and ventilating system for the primary auxiliary building is to provide sufficient circulation of filtered outside air for removal of heat generated by lighting and equipment in the summer and to offset building heat losses in the winter, in rooms and areas of the primary auxiliary building. The primary auxiliary building ventilation and heating system (primary auxiliary building air handling system) also supplies conditioned air to the fuel storage building and makeup to the containment enclosure area. Under normal operating conditions, the charging pump rooms are exhausted through this heating and ventilating system.
| |
| 2.3.3.28.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the primary auxiliary building air handling system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the primary auxiliary building air Structures and Components Subject to Aging Management Review 2-88 handling system mechanical components as subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.29 Primary Component Cooling Water System 2.3.3.29.1 Summary of Technical Information in the Application The primary component cooling water system supplies flow to the following safety
| |
| -related components, which are required for safe shutdown or to ameliorate the consequences of an accident or both:
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| * containment building spray pumps
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| * containment building spray heat exchangers
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| * RH pumps
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| * RH heat exchangers
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| * SI pumps
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| * centrifugal charging pumps
| |
| * containment enclosure coolers The system serves as an intermediate fluid barrier between the reactor coolant and service water systems, ensuring that leakage of radioactive fluid from the components being cooled is not released to the environment.
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| The primary component cooling water system consists of loop A and loop B, which are two independent and redundant flow loops, and an RCP thermal barrier loop. Loops A and B each supply component cooling water to one of the redundant components performing engineered safety-related functions to the RCP thermal barrier loop and to other nonsafety
| |
| -related loads.
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| A supply and return cross connect and a primary component cooling water head tank outlet line cross connect are included in the system design. Each cross connect consists of two isolation valves. These valves are locked closed when two independent primary component cooling water trains are required to be operable, in accordance with plant technical specifications.
| |
| The RCP thermal barrier loop is designed to provide 100 percent of the cooling capacity required to cool the RCP thermal barrier cooling coils under all normal plant operating conditions. The RCP thermal barrier loop has been classified as nonessential, but it incorporates the following special design features to provide a high degree of reliability:
| |
| * Primary component cooling water loops A and B each provide cooling to the RCP thermal barrier loop.
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| * Pipe supports and pressure
| |
| -retaining system components are designed in accordance with ASME Code Section III safety Class 3 and seismic Category I requirements.
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| * Flow instrumentation trains to the annunciator, pumps, pump drive motors, and associated controls are redundant, are qualified to 1E requirements, and are designed to operate with power from the diesel generators in the event of a loss of offsite power.
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| * Instrument sensing lines are designed in accordance with the requirements of Independent Safety Analysis (ISA) Standard 67.02
| |
| -1980, "Instrument Sensing Line
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| | |
| Structures and Components Subject to Aging Management Review 2-89 Piping and Tubing Standards for Use in Nuclear Power Plants."
| |
| Those portions of the primary component cooling water system that furnish cooling water to safety-related components are designated safety Class 3, seismic Category I, and are located in seismic Category I structures. The cross connects are designated safety Class 3, seismic Category I and are located in seismic Category I structure.
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| To provide increased reliability for cooling safety
| |
| -related components, a cross connect from the fire protection and demineralized water systems to the primary component cooling water system is included in the system design. This cross connect can be used to provide cooling water to the charging pump lube oil coolers or provide emergency makeup water to safety
| |
| -related portions of the primary component cooling water system. This cross connect is backed up by a seismic Category I service water system and booster pump makeup source.
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| Those portions of the primary component cooling water system that are non
| |
| -seismic Category I portions of the system are isolated in the event of a leak. The isolation valves will close on a primary component cooling water head tank low
| |
| -level alarm. Thus, the system safety function is not compromised in the event of a leak in the nonsafety portion of the system.
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| 2.3.3.29.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.29, UFSAR Section 9.2.2, UFSAR Tables 6.2
| |
| -83, 7.4-1, and 7.5-1, and the license renewal boundary drawings using the evaluation methodology described in SER Section 2.3 and the guidance in SRP
| |
| -LR Section 2.3. The staff's review identified areas in which additional information was required to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.
| |
| In RAI 2.3.3.29
| |
| -01, dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff noted on LRA drawing PID CC-LR20205, at locations C
| |
| -5 and F-7, that the applicant depicts sections of safety
| |
| -related piping connected to nonsafety
| |
| -related piping that continue onto LRA drawing PID DM-LR20350. However, the seismic anchors could not be located on the nonsafety-related piping beyond the safety and nonsafety interface on LRA drawing PID DM-LR20350. The applicant was asked to provide the seismic anchor locations on the nonsafety-related piping, as described above, beyond the safety and nonsafety interface.
| |
| In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant stated that seismic anchors were not depicted on both LRA drawings since all of the demineralized water system piping in the primary auxiliary building was included within the scope of license renewal under 10 CFR 54.4(a)(2) for structural support. The applicant did indicate that a seismic anchor is physically located on piping approximately 6 ft from the safety-related to nonsafety
| |
| -related interface in one area of LRA drawing PID CC-LR20205. The applicant also stated that the extent of the continued piping and supports ensure that nonsafety-related piping loads are not transferred through the safety and nonsafety interface, as determined by its piping stress analysis.
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| Based on its review, the staff finds the applicant's response to RAI 2.3.3.29
| |
| -01 acceptable because all of the nonsafety
| |
| -related piping in the primary auxiliary building was included within the scope of license renewal under 10 CFR 54.4(a)(2) for structural support. Therefore, the staff's concern described in RAI 2.3.3.29
| |
| -01 is resolved.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-90 In RAI 2.3.3.29
| |
| -02, dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff noted on an LRA drawing that the applicant depicts a section of 1
| |
| -in. piping within the scope of license renewal under 10 CFR 54.4(a)(2). However, the applicant depicts the 1
| |
| -in. piping as excluded from the scope of license renewal in the continuation LRA drawing. The applicant was asked to justify the exclusion of the 1
| |
| -in. piping from the scope of license renewal in LRA drawing PID CS-LR20727. In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant stated that the 1-in. piping shown on the LRA drawing PID CS-LR20727 for the primary auxiliary building is excluded from the scope of license renewal due to the chiller surge tank and its associated piping being in the state of dry layup (i.e., not fluid filled).
| |
| The applicant also stated that the LRA drawing erroneously depicted the 1
| |
| -in. piping as being within the scope of license renewal.
| |
| Based on its review, the staff finds the applicant's response to RAI 2.3.3.29
| |
| -02 acceptable. The staff agrees with the applicant's justification of excluding the above 1
| |
| -in. piping from the scope of license renewal due to its attachment to the chiller surge tank, which is in dry layup and not within the scope of license renewal. Therefore, the staff's concern described in RAI 2.3.3.29
| |
| -02 is resolved.
| |
| In RAI 2.3.3.29
| |
| -03, dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff made the following two observations involving the applicant's usage of its methodology described in LRA Section 2.1.2.2.2:
| |
| * On LRA drawings PID CC-LR20205 (loop A) and PID CC-LR20211 (loop B), respectively, the applicant depicts sections of safety
| |
| -related piping connected to nonsafety-related piping that are within the scope of license renewal under 10 CFR 54.4(a)(2). No seismic anchors are indicated on these LRA drawings. These lines continue on LRA drawing PID FP-LR20268, at location B
| |
| -9, where seismic anchors could not be located on the nonsafety
| |
| -related piping beyond the safety and nonsafety interface.
| |
| * On LRA drawing PID-1-CC-LR20211, the applicant depicts a section of safety
| |
| -related piping connected to nonsafety
| |
| -related piping as being within the scope of license renewal. The piping continues onto LRA drawing PID DM-LR20350, where a seismic anchor could not be located on the nonsafety
| |
| -related piping beyond the safety and nonsafety interface.
| |
| The applicant was asked to provide the seismic anchor locations on the nonsafety
| |
| -related piping beyond the safety and nonsafety interface as described in both of the above issues. In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant addressed the first issue by stating that for LRA drawings PID CC-LR20205 (loop A) and PID-1-CC-LR20211 (loop B), seismic anchors are excluded on the nonsafet y-related piping beyond the safety and nonsafety interface because the nonsafety
| |
| -related piping, which continues onto LRA drawing PID CC-LR20205 does the following:
| |
| * provides structural support for the piping beyond the safety and nonsafety interface
| |
| | |
| Structures and Components Subject to Aging Management Review 2-91
| |
| * ensures that nonsafety
| |
| -related piping loads are not transferred through the interface as determined by its piping stress analysis For the second issue, the applicant stated that for LRA drawing PID CC-LR20211, seismic anchors are excluded on the nonsafety
| |
| -related piping beyond the safety and nonsafety interface because the piping, which continues onto LRA drawing PID DM-LR20350, does the following:
| |
| * provides structural support for the piping beyond the safety and nonsafety interface
| |
| * ensures that nonsafe ty-related piping loads are not transferred through the interface as determined by its piping stress analysis Based on its review, the staff finds the applicant's response to RAI 2.3.3.29
| |
| -03 acceptable because the applicant explained that no seismic anchors are required because the piping stress analyses determined that nonsafety
| |
| -related piping loads are not transferred through the interface. Therefore, the staff's concern described in RAI 2.3.3.29
| |
| -03 is resolved.
| |
| 2.3.3.29.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI responses, and license renewal boundary drawings to determine whether the applicant had identified all components within the scope of license renewal. In addition, the staff's review determined whether the applicant had identifie d all components subject to an AMR. On the basis of its review, the staff concludes the applicant appropriately identified the primary component cooling water system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
| |
| 2.3.3.30 Radiation Monitoring System 2.3.3.30.1 Summary of Technical Information in the Application The radiation data management system (radiation monitoring (RM) system) consists of three subsystems: the process and effluent RM system, the area RM system, and the airborne and particulate radioactivity monitoring system. The functional performance requirements for the RM system include the following:
| |
| * warn of leakage from process systems containing radioactivity
| |
| * monitor the amount of radioactivity released in effluents
| |
| * isolate lines containing liquid and gaseous activity when activity levels reach a preset limit
| |
| * record the radioactivity present in various station systems and effluent streams
| |
| * provide a means for leakage detection
| |
| * provide information on failed fuel
| |
| * monitor plant areas within the radiologically controlled area for radiation 2.3.3.30.2 Conclusion
| |
| | |
| Structures and Components Subject to Aging Management Review 2-92 Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the RM system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the RM system mechanical components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.31 Reactor Makeup Water System 2.3.3.31.1 Summary of Technical Information in the Application The reactor makeup water system provides the storage and distribution of reactor grade water. It also provides storage capacity for water recycled by the boron recovery system.
| |
| The reactor makeup water system consists of one reactor makeup water storage tank, two redundant, full capacity reactor makeup water pumps, and associated piping, valves, instrumentation, and controls.
| |
| The intended functions of the reactor makeup water system component types within the scope of license renewal include the following:
| |
| * maintain system interface with the CS and the containment building spray system
| |
| * provide post
| |
| -accident monitoring
| |
| * provide containment isolation function LRA Table 2.3.3
| |
| -31 lists the reactor makeup water system components types that require an AMR. 2.3.3.31.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the reactor makeup water system components within the scope of license renewal, as required by 10 CFR 54.4(a).
| |
| The staff also concluded that the applicant adequately identified the reactor makeup water system components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.32 Release Recovery System 2.3.3.32.1 Summary of Technical Information in the Application The release recovery system contains and quenches relief valve discharge from the CS and boron recovery system degasifiers as well as the boron recovery system, steam generator blowdown system, and waste processing liquid system evaporators.
| |
| Release recovery tank, 1
| |
| -RR-TK-258, is in
| |
| -scope for license renewal from a spatial consideration due to its location in the primary auxiliary building. The relief valve in the degasifier system opens at 60 psig to direct flow to the release recovery tank, 1
| |
| -RR-TK-258, located in the primary auxiliary building hallway, outside the degasifier cubicle. Quench tank, 1-RR-TK-258, and the release recovery system piping will normally be under a nitrogen Structures and Components Subject to Aging Management Review 2-93 blanket to eliminate the potential for explosive gas mixtures if H 2 is present in the relieving fluid. Under normal conditions, 1
| |
| -RR-TK-258 will be half filled with demineralized water to ensure that quenching of a design
| |
| -base release can be accomplished. The tank is designed for an 8-second release from full open 1
| |
| -RR-V-655. 2.3.3.32.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the release recovery system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the release recovery system mechanical components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.33 Resin Sluicing System 2.3.3.33.1 Summary of Technical Information in the Application The spent resin sluicing (RS) system collects the spent resin from all the demineralizers and ion exchangers of the nuclear plant.
| |
| 2.3.3.33.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the RS system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the RS system mechanical components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.34 Roof Drains System 2.3.3.34.1 Summary of Technical Information in the Application The roof drains system is nonsafety related. It is installed on major buildings that have relatively flat roofs. The system removes rainwater and water from melting snow from the roof. It consists of roof
| |
| -mounted strainers that collect the water and transport it through connected ceiling-mounted pipes to the storm drain system (not within the scope of license renewal). The plant's dewatering system discharges water to the roof drains system, which then flows to the storm drain system and out to the circulating water system for discharge.
| |
| 2.3.3.34.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.34 and the license renewal boundary drawings using the evaluation methodology described in SER Section 2.3 and the guidance in SRP
| |
| -LR Section 2.3. The staff's review identified an area in which additional information was required to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAI, as discussed below.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-94 In RAI 2.3.3.34
| |
| -01, dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff noted on LRA drawing, PID-1-DR-LR20633, that the applicant depicts 6
| |
| -in. lines that continue onto LRA drawing PID SD-LR20402. On LRA drawing PID DR-LR20633, the applicant depicts 6-in. piping that enters the continuation flag marked "B" as being included within scope of license renewal under 10 CFR 54.4(a)(2). The applicant depicts the other 6
| |
| -in. piping that enters the continuation flag, marked "C," as being excluded from scope of license renewal. However, the applicant depicts on the continuation LRA drawing, PID SD-LR20402, the 6
| |
| -in. piping for "B" as being excluded from scope of license renewal, while the other 6
| |
| -in. piping for "C" is shown as being included within scope of license renewal. The applicant was asked to clarify the scoping classifications of both 6-in. piping sections on both LRA drawings.
| |
| In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant stated that the 6
| |
| -in. piping in LRA drawing PID SD-LR20402, which is marked with the "B" continuation flag, is within scope of license renewal under 10 CFR 54.4(a)(2) up to the area where it exits the emergency feedwater pumphouse (EFPH). The applicant also stated that the 6-in. piping in LRA drawing PID DR-LR20633, which is marked with the "B" continuation flag, was excluded from scope of license renewal from where it exits the EFPH. Lastly, the applicant stated that the 6
| |
| -in. piping in LRA drawing PID SD-LR20402, which is marked with the "C" continuation flag, was excluded from scope of license renewal from where it exits the EFPH. The applicant indicated that both 6
| |
| -in. roof drain lines in the EFPH are within the scope of license renewal up to the point where they exit the EFPH.
| |
| Based on its review, the staff finds the applicant's response to RAI 2.3.3.34
| |
| -01 acceptable because the applicant explained that the piping in the EFPH is within the scope of license renewal. The piping is not within the scope of license renewal after it leaves the EFPH. Therefore, the staff's concern described in RAI 2.3.3.34
| |
| -01 is resolved. 2.3.3.34.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI response, and license renewal boundary drawings to determine whether the applicant had identified all components within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all components subject to an AMR. On the basis of its review, the staff concludes the applicant appropriately identified the roof drains system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
| |
| 2.3.3.35 Sample System 2.3.3.35.1 Summary of Technical Information in the Application The sample subsystems from the reactor coolant, steam generators, and other auxiliary systems provide representative gas and liquid samples for laboratory analysis, in accordance with Positions C.6 and C.7 in RG 1.21, "Measuring, Evaluating, and Reporting Material in Liquid and Gaseous Effluents and Solid Waste." Typical information obtained includes reactor coolant boron, sodium ion and halogen concentrations, fission product radioactivity level, H 2 , oxygen, and fission gas content, corrosion product concentration, and chemical additive concentration. The sample subsystem for secondary steam and water systems provides Structures and Components Subject to Aging Management Review 2-95 representative samples for measuring specific and cation conductivity, concentrations of sodium ion, dissolved oxygen, and hydrazine.
| |
| The system is divided into five subsystems
| |
| -reactor coolant sampling, steam generator blowdown sampling, auxiliary system sampling, secondary steam and water sampling, and post-accident sampling.
| |
| 2.3.3.35.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.35, UFSAR Sections 9.2.3.1 and 9.3.2.2, UFSAR Tables 6.2
| |
| -83 and 7.5
| |
| -1, and the license renewal boundary drawings using the evaluation methodology described in SER Section 2.3 and the guidance in SRP
| |
| -LR Section 2.3. The staff's review identified an area in which additional information was required to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAI, as discussed below.
| |
| In RAI 2.3.3.35
| |
| -01, dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff noted on LRA drawing PID SB-LR20626, at location B
| |
| -12, that the applicant depicts a section of 3
| |
| -in. piping within scope of license renewal under 10 CFR 54.4(a)(3). The 3
| |
| -in. piping continues onto LRA drawing PID SB-LR20629, in which the 3
| |
| -in. piping is excluded from scope of license renewal. The applicant was asked to justify the exclusion of this portion of 3-in. piping from scope of license renewal on LRA drawing PID SB-LR20629. In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant stated that the in
| |
| -scope portion of the 3
| |
| -in. piping on LRA drawing PID SB-LR20626 should have ended before continuing onto LRA drawing PID SB-LR20629. The applicant stated that license renewal Note 3 in LRA drawing PID SB-LR20626, which indicates that "[p]ipe exits Waste Process Building Tank Farm area and is not subject to aging management review," should have been labeled near the 3
| |
| -in. piping where it exits the tank farm on the LRA drawing. Based on its review, the staff finds the applicant's response to RAI 2.3.3.35
| |
| -01 acceptable because the staff confirmed that the scoping boundary of the 3
| |
| -in. piping is consistent with license renewal Note 3 in LRA drawing PID SB-LR20626 regarding piping that exits the waste process building tank farm area. Therefore, the staff's concern described in RAI 2.3.3.35
| |
| -01 is resolved.
| |
| 2.3.3.35.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI response, and license renewal boundary drawings to determine whether the applicant had identified all components within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all components subject to an AMR. On the basis of its review, the staff concludes the applicant appropriately identified the sample system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
| |
| | |
| Structures and Components Subject to Aging Management Review 2-96 2.3.3.36 Screen Wash System 2.3.3.36.1 Summary of Technical Information in the Application The service water traveling screens form a full
| |
| -channel mesh strainer that removes debris from the water flowing into each service water pump bay. The debris collected on the screen is removed by a high
| |
| -pressure water spray supplied by the service water screen wash pump.
| |
| The circulating water traveling screens prevent fish and debris from entering the circulating water system. One traveling screen is provided for each circulating water pump bay. Debris is collected on the upstream side of the traveling screen and is carried upward as the screen rotates. As the debris nears the top of screen travel, high velocity jets of water from the screen wash nozzles flush it out.
| |
| The circulating water screen wash pumps are one means to supply the chlorination system with salt water. Flow to the chlorination system from the screen wash system pumps goes through a common header. The sodium hypochlorite metering pumps discharge into this common header.
| |
| During initial startup or total circulating water system shutdown, water is supplied to one of two circulating water lube water pumps from the service water screen wash pump.
| |
| 2.3.3.36.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the screen wash system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the screen wash system mechanical components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.37 Service Water System 2.3.3.37.1 Summary of Technical Information in the Application The service water system was originally designed for two units. The service water pump house has a pump bay for each unit. Each pump bay has two supplies, one from the intake discharge transition structure and one from the discharge transition structure. The Unit 2 supply valves are locked, closed, and de
| |
| -energized. Unit 2 was not completed and is nonoperational. The Unit 2 service water return is blanked off and is not used.
| |
| The Unit 1 service water system consists of two independent and redundant flow trains. Each of these supplies cooling water to a primary component cooling water heat exchanger, a diesel generator jacket water cooler, the secondary component cooling water heat exchangers, the auxiliary secondary component cooling water heat exchangers, the condenser water box priming pump seal water heat exchangers, and
| |
| -except during a LOCA
| |
| -the fire protection system during a fire.
| |
| Flow in each redundant train is supplied by two redundant service water pumps. Each service water pump is capable of supplying 100 percent of the flow required by each flow train to Structures and Components Subject to Aging Management Review 2-97 dissipate plant heat loads during normal full
| |
| -power operation. Thus, for full
| |
| -power operation, two pumps (one pump per flow train) are required.
| |
| The four service water pumps take suction from a common bay in the service water pumphouse. Seawater flow is supplied to the service water pumphouse from the Atlantic Ocean due to the static head of the ocean above the elevation of the service water pump suctions.
| |
| The Atlantic Ocean serves as the normal ultimate heat sink for Seabrook. In the unlikely event that seawater flow to the service water pumphouse is restricted (greater than 95 percent blockage) due to seismically induced damage to the circulating water (seawater) intake and discharge tunnels, a mechanical draft evaporative cooling tower is provided to dissipate shutdown and accident heat loads. The mechanical draft cooling tower is completely independent of the circulating water tunnels and the Atlantic Ocean.
| |
| The cooling tower consists of one independent cell with one fan and a center cell with two fans. A third cell was included for anticipated Unit 2 operation but remains nonfunctional. The cooling tower basin consists of a pump well and one catch basin for each of the two tower spray cells. The unit has an "A" and a "B" cooling tower complex flow train. The cooling tower pumps-with associated valves, piping, and equipment in the trains
| |
| -circulate cooling water from the pump well basin through the primary component cooling heat exchangers, the secondary component cooling water heat exchangers during normal operations, the diesel generator heat exchangers during loss of offsite power conditions, or both during testing. Makeup to the cooling tower can be provided by a portable tower makeup pump (in the event that normal makeup source is unavailable and the service water pumps are unavailable). RG 1.27, "Ultimate Heat Sink for Nuclear Power Plants," requires a heat sink capable of providing cooling for 30 days; the cooling tower has a 7
| |
| -day supply. The cooling tower makeup pump is tested every 18 months per technical specifications. After the pump is tested, it is flushed with potable water. It is capable of providing makeup water to the tower basin from the nearby Browns River or Hampton Harbor, with several locations accessible by road. It consists of 3,000 ft of 5
| |
| -in. rubber
| |
| -lined polyester flexible hose and associated hose couplings and a portable diesel
| |
| -driven pump that is self
| |
| -priming within 15 ft of water level, and it is designed to deliver a minimum of 200 gallons per minute (gpm) from the water source to the tower basin. The 7-day period that the tower can operate without makeup water provides sufficient time to move the pump into position, lay the hose, and make the system ready for operation.
| |
| 2.3.3.37.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.37, UFSAR Sections 9.2.1 and 9.2.5, UFSAR Tables 7.4-1 and 7.5-1, and the license renewal boundary drawings using the evaluation methodology described in SER Section 2.3 and the guidance in SRP
| |
| -LR Section 2.3. The staff's review identified an area in which additional information was required to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAI, as discussed below.
| |
| In RAI 2.3.3.37
| |
| -01, dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff noted on LRA drawing PID SW-LR20795, at locations B
| |
| -11 and C-12, that the applicant depicts strainers within scope of license renewal under 10 CFR 54.4(a)(1). However, the component type "strainer" and its component intended function(s) are not included in LRA Structures and Components Subject to Aging Management Review 2-98 Table 2.3.3
| |
| -37. The applicant was asked to justify the exclusion of the strainer and its component intended function(s) from LRA Table 2.3.3
| |
| -37. In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant stated that the strainers are evaluated as component type "filter housing" with an intended function of "pressure boundary" in LRA Table 2.3.3
| |
| -37. The applicant also stated that the screen portion of the strainer was evaluated as component type "filter element" with an intended function of "filter" in LRA Table 2.3.3
| |
| -37. Based on its review, the staff finds the applicant's response to RAI 2.3.3.37
| |
| -01 acceptable because the staff confirmed that both the component types, "filter housing" and "filter," are included in LRA Table 2.3.3
| |
| -37. Therefore, the staff's concern described in RAI 2.3.3.37
| |
| -01 is resolved. 2.3.3.37.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI response, and license renewal boundary drawings to determine whether the applicant had identified all components within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all components subject to an AMR. On the basis of its review, the staff concludes the applicant appropriately identified the service water system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
| |
| 2.3.3.38 Service Water Pump House Air Handling System 2.3.3.38.1 Summary of Technical Information in the Application The service water pump house heating and ventilation systems comprise the heating and ventilation systems for the pump room area of the service water pump house.
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| The ventilation function is provided by the service water pump house air handling system. The heating function is provided by the HW system and is evaluated separately.
| |
| The pump room area is ventilated and cooled with outside air supplied through pneumatically-operated dampers, and it is exhausted through exhaust fans and backdraft dampers. Each exhaust fan, and its associated supply air damper, is controlled by a separate thermostat located in the pump room area. The thermostat settings are staggered such that the fans will start in sequence. Each fan is powered by a separate and independent engineered safety features electrical train. Each supply air damper is designed to fail open on loss of air or electric power to its solenoid valve.
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| The switchgear areas of the service water pump house, one for electrical train A equipment and the other for electrical train B equipment, are ventilated with filtered outside air supplied by one of two full
| |
| -sized supply fans through a seismically supported duct system. Each fan is powered by a separate and independent engineered safety features electrical train. Air is drawn from the outside through a roll
| |
| -type filter, a fan, or a backdraft damper and is then distributed through ductwork into the two switchgear areas. Air is exhausted from each switchgear area through its respective relief damper. There are two thermostats per fan to Structures and Components Subject to Aging Management Review 2-99 control its operation, one in train A switchgear room and the other in train B switchgear room. Both the thermostats on the lead fan have identical set points.
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| The service water cooling tower heating and ventilation systems comprise a heating system and a ventilation system for each redundant switchgear room and a ventilation system for the pump room. Each switchgear room and the pump room are ventilated by drawing air from, and exhausting to, the outside.
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| Ventilation and cooling air is drawn into the ventilation and mechanical equipment area of the pump room from the outside through fixed louvers and a roughing filter.
| |
| Cooling of the pump room area, when required, is accomplished by redundant exhaust fans. Each fan is controlled by its individual thermostat. Thermostats are set so if one thermostat, fan, or its power supply fails, the redundant fan, served by a separate Class 1E power supply, will start before overheating occurs.
| |
| Each of the two cooling tower switchgear rooms is supplied with ventilating and cooling air, when required, from its own independent supply fan located in the mechanical equipment area. The supply air fan for each switchgear room is provided electrical power for a Class 1E power source, which is independent of the other three. Each supply fan is cycled by a thermostat located in its respective switchgear room. Supply air is directed to the switchgear room via sheet metal ductwork. Heat
| |
| -laden air from the switchgear rooms is exhausted through a relief damper to the outside.
| |
| 2.3.3.38.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the service water pump house air handling system components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the service water pump house air handling system components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.39 Spent Fuel Pool Cooling System 2.3.3.39.1 Summary of Technical Information in the Applicati on The functions of the spent fuel pool cooling and cleanup system include the following:
| |
| * continuously remove decay heat generated by fuel elements stored in the pool
| |
| * continuously maintain a minimum of 13 ft of water over the spent fuel elements to shield personnel
| |
| * maintain the chemical parameters and optical clarity of the spent fuel pool water and the water in the reactor cavity and refueling canal during refueling operations All portions of the spent fuel pool cooling loop are designated safety Class 3 and are designed and constructed to meet seismic Category I requirements. Those portions of the cleanup system not designed to these requirements are normally isolated from the cooling loop.
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| | |
| Structures and Components Subject to Aging Management Review 2-100 The spent fuel pool cooling and cleanup system comprises three subsystems: the spent fuel pool cooling subsystem, the spent fuel pool cleanup subsystem, and the reactor cavity and canal cleanup subsystem.
| |
| Spent Fuel Pool Cooling Subsystem. The spent fuel cooling pumps take suction from the pool and circulate water through the heat exchangers, which are cooled by the primary component cooling water system. Pool water enters the suction line through a strainer near one wall of the pool at a point 13 ft higher than the return line terminations. The return lines are located at a sufficient distance from the suction line to ensure adequate circulation and uniform pool water temperatures. All system connections to the fuel pool penetrate at elevations sufficiently above the top of the fuel to maintain adequate shielding in the event the water level drains to the penetration level. Piping arrangement precludes siphoning below this level. All components in contact with the spent fuel cooling water are stainless steel. The spent fuel pool pump motors are Class 1E motors. Pumps 1
| |
| -SF-P-10A and 1-SF-P-10B are powered from separate emergency busses. Pump 1
| |
| -SF-P10C can be aligned to be powered from either emergency bus.
| |
| Spent Fuel Pool Cleanup Subsystem. Spent fuel pool water quality is maintained by a pool skimmer loop, which filters and demineralizes the circulated water. The pool skimmer loop consists of five pool surface skimmers, a skimmer pump, two filters, and a demineralizer. This system is used to maintain the pool surface free from floating particles and other materials and to remove radioactive materials in the water. The system is sized to process approximately 120 gpm, which means that one
| |
| -half of the pool volume is processed in a day. All spent fuel pool cooling and cleanup system equipment is located in the fuel storage building, except the filters and demineralizer, which are located in the demineralizer area of the primary auxiliary building. The skimmer pump motor is not Class 1E and is supplied from a local control center. The spent fuel pool cleanup subsystem can also be used to purify the RWST water, drain the water in the cask loading and fuel transfer canal areas (using a submersible pump), and purify the refueling cavity water during refueling operations. A cleanup system (1
| |
| -CBS-SKD-161) is also used for RWST or spent fuel pool processing.
| |
| Reactor Cavity and Canal Cleanup Subsystem. The reactor cavity cleanup portion of the system is designed to purify the reactor cavity during refueling operations to improve the optical clarity of the water. The system consists of five surface skimmers at the water surface of the refueling cavity and canal and three drains, all piped to the suction of the reactor cavity cleanup skimmer pump via a lead
| |
| -shielded disposable cartridge type filter unit. The lead
| |
| -shielded filter removes radioactive particulates in the refueling water in order to prevent crud buildup in socket
| |
| -welded piping downstream of the skimmer pump. This filter also minimizes crud buildup in the CS and spent fuel pool cleanup system filters and demineralizers depending on the particular lineup. The cavity water is pumped through the CS mixed bed demineralizer and filters to the suction of the RH pumps where it is returned to a cold leg through an RH heat exchanger. During cavity drain down upon completion of refueling, refueling water can be routed via the reactor cavity cleanup system to the RWST via the spent fuel pool cleanup system. Also, the reactor cavity cleanup system may be used to send refueling water to the liquid waste system floor drain tanks. This lineup would be primarily used at the conclusion of drain down when the residual refueling water may not be suitable for return to the RWST. As an alternative to using the installed cavity cleanup pump and shielded filter, a provision exists
| |
| | |
| Structures and Components Subject to Aging Management Review 2-101 to install temporary equipment between isolation valves 1
| |
| -SF-V-81 and 85. The reactor cavity cleanup pump motor is not Class 1E, and it is supplied from a motor control center in the control building.
| |
| 2.3.3.39.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.39, UFSAR Sections 9.1.2 and 9.1.3, and the license renewal boundary drawings using the evaluation methodology described in SER Section 2.3 and the guidance in SRP
| |
| -LR Section 2.3. The staff's review identified areas in which additional information was required to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAIs, as discussed below.
| |
| In RAI 2.3.3.39
| |
| -01, dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff noted on LRA drawing PID SF-LR20484 that the applicant refers to license renewal Note 1, which states "[t]hese components are drained during operation so therefore they have an internal environment of air/gas so they have no license renewal (LR) intended function and not in scope." However, on LRA drawing PID DM-LR20353, license renewal Note 1 indicates refueling canal skimmer pump SF
| |
| -P-272 is a component that is in
| |
| -scope for license renewal, which contradicts license renewal Note 1 on LRA drawing PID SF-LR20484. Additionally, the portion of the line excluded from the scope of license renewal is directly connected to the pump P-272 and continues onto the refueling pool and canal skimmers. LRA Table 3.3.2
| |
| -39 does not provide an internal environment of air or gas for pump casing. The applicant was asked to clarify the scoping designation of the piping directly connected to the refueling canal skimmer pump.
| |
| In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant stated the pump SF
| |
| -P-272 is a nonsafety
| |
| -related pump and is in operation only during refueling outages when the refueling pool and canal are flooded. The applicant also stated that the pump and associated piping are drained during normal power operation and are excluded from scope of license renewal. The applicant described that license renewal Note 1, found in LRA drawing PID DM-LR20353, refers to only the mechanical seal supply system piping attached to the pump mechanical seal in containment as being included within scope of license renewal under 10 CFR 54.4(a)(2).
| |
| Based on its review, the staff finds the applicant's response to RAI 2.3.3.39
| |
| -01 acceptable because the SF
| |
| -P-272 pump and its piping do not have any license renewal
| |
| -intended functions and are drained during normal power operation. Therefore, the staff's concern described in RAI 2.3.3.39
| |
| -01 is resolved.
| |
| In RAI 2.3.3.39
| |
| -02, dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff identified a discrepancy between the CLB and LRA descriptions of the alternate spent fuel pool cooling (ASFPC) heat exchanger. The applicant states in the UFSAR that the ASFPC heat exchanger is available and can be placed in service as needed. However, the applicant also describes in the LRA that the ASFPC heat exchanger is blank
| |
| -flanged and is in abandoned status. The applicant was asked to clarify if the ASFPC heat exchanger is available as part of the spent fuel pool cooling system and if the component is in
| |
| -scope for license renewal.
| |
| In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant stated that a UFSAR change request has been issued to remove the discussion of the ASFPC from the UFSAR, excluding it from scope of license renewal. The applicant indicated that Structures and Components Subject to Aging Management Review 2-102 UFSAR Section 9.1.3.1 has been revised to indicate the ASFPC system is no longer required and is isolated from the service water and spent fuel pool cooling systems. The applicant stated that other sections in the UFSAR that reference the ASFPC were also deleted.
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| Based on its review, the staff finds the applicant's response to RAI 2.3.3.39
| |
| -02 acceptable because the ASFPC is isolated from the service water and spent fuel pool cooling systems; thereby excluding it from scope of license renewal. The applicant stated that a UFSAR change request has been issued to remove all references to the ASFPC heat exchanger. Therefore, the staff's concern described in RAI 2.3.3.39
| |
| -02 is resolved.
| |
| 2.3.3.39.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI responses, and license renewal boundary drawings to determine whether the applicant had identified all components within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all components subject to an AMR. On the basis of its review, the staff concludes the applicant appropriately identified the spent fuel pool cooling system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
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| 2.3.3.40 Switchyard 2.3.3.40.1 Summary of Technical Information in the Application The 345-kV switching station consists of metal
| |
| -enclosed, gas
| |
| -insulated components (circuit breakers, disconnect switches, buses, surge arresters, potential devices, etc.) connected by an integral bus system. Pressurized sulphur hexafluoride (SF 6), a nonflammable, nontoxic gas, is used as the insulating and arc
| |
| -quenching medium. Each circuit breaker and each bus section of the 345
| |
| -kV switching station forms a separate gas
| |
| -insulated system that is individually monitored as a three
| |
| -phase system. Each three
| |
| -phase circuit breaker is supplied with its own self-contained SF 6 gas system. There is no interconnection between the circuit breaker SF 6 gas systems and the switching station gas systems.
| |
| The bus section gas systems include the three
| |
| -phase bus connections between two circuit breakers, extending to the point of connection to a transformer or to an overhead line. Metal
| |
| -enclosed, SF 6-insulated buses connect the 345
| |
| -kV switching station directly to the high
| |
| -voltage bushings of the generator step
| |
| -up (GSU) transformers and the reserve auxiliary transformers (RATs). The electrical configuration of the 345 kV switching station is a breaker
| |
| -and-half arrangement.
| |
| 2.3.3.40.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the switchyard mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the switchyard mechanical components subject to an AMR, as required by 10 CFR 54.21(a)(1).
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| | |
| Structures and Components Subject to Aging Management Review 2-103 2.3.3.41 Valve Stem Leak
| |
| -off System 2.3.3.41.1 Summary of Technical Information in the Application The valve stem leak
| |
| -off system collects any stem leakage and directs it to a low
| |
| -point drain. This helps reduce the spread of contamination and keeps the water off the floor.
| |
| Initially, all manually and motor
| |
| -operated valves of the RCS, which are 3 in. and larger, were provided with double
| |
| -packed stuffing boxes and intermediate lantern ring leakoff connections. Exceptions to this criterion are gate valves that have been determined to be susceptible to pressure locking, which have been modified to use the valve stem leakoff connection as a vent path for the bonnet cavity. Packing configurations have evolved so that the preferred packing configuration is a single packing set. The industry has moved away from double
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| -packed stuffing boxes. These changes in packing configuration have been approved for use at Seabrook. Accordingly, either packing design configuration is acceptable for use at Seabrook. These valves use only a single packing set. Leakage to the atmosphere is essentially zero for these valves.
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| 2.3.3.41.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.41, UFSAR Sections 9.2.3.1 and 9.3.2.2, UFSAR Tables 6.2
| |
| -83 and 7.5
| |
| -1, and the license renewal boundary drawings using the evaluation methodology described in SER Section 2.3 and the guidance in SRP
| |
| -LR Section 2.3. In addition to the continuation issue identified in RAI 2.3
| |
| -01 described in Section 2.3.3, the staff's review identified areas in which additional information was required to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAIs, as discussed below.
| |
| In RAI 2.3.3.41
| |
| -01, dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff noted on LRA drawing PID VSL-LR20776, at locations F
| |
| -4 and F-11, that the applicant depicts four vent pipelines within scope for license renewal under 10 CFR 54.4(a)(2). However, the valves associated with these vent lines are not listed on LRA Table 2.3.3
| |
| -41 as a valve component type with intended function(s). The applicant was asked to justify the exclusion of the valves from LRA Table 2.3.3
| |
| -41. In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant stated the valves are the instrument vent valves for the primary component cooling water system flow indicating switches. The applicant indicated that the instrument valves are within scope of license renewal under the primary component cooling water system as a commodity. The applicant also indicated that a system flag designator should have been included on LRA drawing PID VSL-LR20776 to denote that the vent valves were part of the primary component cooling water system.
| |
| Based on its review, the staff finds the applicant's response to RAI 2.3.3.41
| |
| -01 acceptable because the staff confirmed that the instrument vent valves were already included within scope of license renewal as instrument commodities for the primary component cooling water system. Therefore, the staff's concern described in RAI 2.3.3.41
| |
| -01 is resolved.
| |
| In RAI 2.3.3.41
| |
| -02, dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff noted on LRA drawing PID VSL-LR20776, at locations F
| |
| -4 and F-11, that the applicant Structures and Components Subject to Aging Management Review 2-104 depicts four vent pipelines within scope of license renewal under 10 CFR 54.4(a)(2). However, the seismic anchors could not be located on the nonsafety-related piping beyond the safety and nonsafety interface. The applicant was asked to provide the seismic anchor locations on the nonsafety
| |
| -related piping beyond the safety and nonsafety interface.
| |
| In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant stated that the safety
| |
| -related piping to nonsafety
| |
| -related piping (or tubing) transition is through a flexible connector. The applicant explained that seismic anchors are not required since the flexible connectors decouple the piping system and negate a transfer of loads. However, the applicant indicated that the entire nonsafety
| |
| -related piping (or tubing) was included within the scope of license renewal and subject to an AMR to ensure adequate protection of the safety
| |
| -related piping. The applicant also indicated that the instrument racks, which contain the instruments that connect to the tubing, serve as the seismic anchors for the valves, tubing, and instruments and are also included within the scope of license renewal. Based on its review, the staff finds the applicant's response to RAI 2.3.3.41
| |
| -02 acceptable because the nonsafety
| |
| -related piping beyond the safety and nonsafety interface and connected to the instrument racks was already included within the scope of license renewal and subject to AMR. Therefore, the staff's concern described in RAI 2.3.3.41
| |
| -02 is resolved.
| |
| 2.3.3.41.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI responses, and license renewal boundary drawings to determine whether the applicant had identified all components within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all components subject to an AMR. On the basis of its review, the staff concludes the applicant appropriately identified the valve stem leak
| |
| -off system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the mechanical components subject to an AMR in accordance with t he requirements stated in 10 CFR 54.21(a)(1).
| |
| 2.3.3.42 Vent Gas System 2.3.3.42.1 Summary of Technical Information in the Application The equipment vent gas (VG) system consists of three separate and distinct headers: an aerated vent header, a hydrogenated vent header, and a reactor coolant vent header. Local vents are not considered a part of this system but are vented to nearby ventilation system ducts. Aerated Vent Header. The aerated vent header receives vent gas that is predominantly air plus radioactive contaminants from various components in the boron recovery system, liquid waste system (waste processing liquid system), waste solidification system, steam generator blowdown system, equipment and floor drainage system (waste processing liquid drains system), and the letdown degasifier during an oxygenated letdown sequence. The gas is then filtered and discharged to the atmosphere via the primary auxiliary building normal ventilation cleanup exhaust unit.
| |
| Hydrogenated Vent Header: The hydrogenated vent header collects radioactive contaminated H 2 gas from the reactor coolant drain tank, chemical volume control tank, pressurizer relief Structures and Components Subject to Aging Management Review 2-105 tank sample vessel, chemical volume control tank sample vessel, primary drain tank, primary drain tank degasifier, and the letdown degasifier. Additionally, dependent on gaseous activity, the pressurizer may be purged to the hydrogenated vent header in preparation for outages. The collected gas is then processed through the radioactive gaseous waste system (WG system). The safety valve surge tank provides additional header capacity and reduces the magnitude of pressure fluctuations within the header. A pressure
| |
| -regulating valve maintains a constant pressure of 2 psig in the influent line of the radioactive gaseous waste system that serves to isolate the radioactive gaseous waste system influent line from hydrogenated vent header pressure surges.
| |
| Reactor Coolant Vent Header. The reactor coolant vent header provides for the evacuation of the RCS during filling operations. Additionally, dependent on gaseous activity, the pressurizer may be purged to the hydrogenated vent header via the reactor coolant vent header in preparation for outages. During normal plant operations, the reactor coolant vent header is isolated from the hydrogenated vent header by a locked closed valve. Prior to the RCS filling operation, the hydrogenated vent header is isolated from the reactor coolant vent header, except for a path to the primary auxiliary building exhaust unit, and the line is purged with nitrogen. The reactor coolant vent header is then connected to the components and piping of the RCS by the insertion of a spool piece between the vent line. A separator and silencer separates any entrained liquid, which is then drained to containment sump "A." Prior to entering an outage and the opening of the RCS, the pressurizer gas space may be purged to the primary auxiliary building exhaust unit or the hydrogenated vent header dependent on gaseous activity. When routed to the hydrogenated vent header, the reactor coolant vent header is aligned to the pressurizer via the vent spool and purged with nitrogen. Following completion of the pressurizer purge, the reactor coolant vent header is isolated from the hydrogenated vent header. An evacuation pump is used during filling operations to direct the air from the reactor coolant vent header to the hydrogenated vent header, where it is filtered and discharged to the atmosphere.
| |
| 2.3.3.42.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the VG system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the VG system mechanical components subject to an AMR, as required by 10 CFR 4.21(a)(1).
| |
| 2.3.3.43 Waste Gas System 2.3.3.43.1 Summary of Technical Information in the Application Hydrogenated fission product gases
| |
| -from the reactor coolant letdown stream and from the liquids collected in the primary drain tank and the reactor coolant drain tank
| |
| -are processed in the radioactive gaseous waste (WG) system. An iodine guard bed and a molecular sieve dryer reduce the contamination level of the gases before further processing by the carbon delay beds. The carbon delay beds provide a minimum of 60 days of xenon delay and 85 hours of krypton delay. Low
| |
| -activity aerated gas streams from the reactor plant aerated vent header Structures and Components Subject to Aging Management Review 2-106 and condenser vacuum pump units are filtered, monitored, and discharged to the plant unit vent. The WG system is designed to provide sufficient processing so that gaseous effluents are discharged to the environment at concentrations below the regulatory limits of 10 CFR Part 20, "Standards for Protection Against Radiation," and within the "as low as is reasonably achievable" guidelines set forth in 10 CFR Part 50, Appendix I, "Numerical Guides for Design Objectives and Limiting Conditions for Operation To Meet the Criterion, 'As Low As Reasonably Achievable,' for Radioactive Material in Light
| |
| -Water-Cooled Nuclear Power Reactor Effluents." The WG system also provides sufficient holdup and control of gaseous releases, as specified in 10 CFR Part 50, Appendix A, GDC 60. The WG system can process a maximum surge flow of 1.2 standard cubic feet per minute (SCFM) from the degasifiers, which is based on the maximum letdown flow of 120 gpm from the RCS to the CS. This represents the most limiting plant operating condition for the WG system.
| |
| The portion of the waste processing building that houses the WG system is seismic Category I.
| |
| The WG system is designated NNS
| |
| -related. H 2 concentration is monitored in cubicles containing WG system components to detect a leak in the system. Monitoring of H 2 concentration is not required while the WG system is inerted with nitrogen. Dual oxygen monitors are provided to sample the process stream to monitor formation of explosive mixtures. An alarm is initiated at a predetermined setpoint prior to reaching a potentially explosive mixture. The WG system is designed to withstand an H 2 explosion.
| |
| The WG stream undergoes one of the following options:
| |
| * It is returned directly to the RCS via the volume control tank or the H 2 injector.
| |
| * It is stored in the H 2 surge tank.
| |
| * It is released to the environment via the equipment vent system.
| |
| * It is recycled to the hydrogenated vent header as makeup gas.
| |
| 2.3.3.43.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the WG system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the WG system mechanical components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.44 Waste Processing Liquid System 2.3.3.44.1 Summary of Technical Information in the Application The liquid waste system (waste processing liquid system) is nonnuclear safety class (NNS) and non-seismic Category I, in accordance with RG 1.26, "Quality Group Classifications and Standards for Water
| |
| -, Steam-, and Radioactive
| |
| -Waste-Containing Components of Nuclear Power Plants," Revision 4, and RG 1.29, "Seismic Design Classification," Revision 4. The liquid waste system is designed to meet applicable requirements specified in 10 CFR Part 20 and 10 CFR Part 50, as follows:
| |
| | |
| Structures and Components Subject to Aging Management Review 2-107
| |
| * provide a central collection point for radioactive liquid waste (This includes approximately 1,200 gal. per week of reactor grade and nonreactor grade leakage from various systems and approximately 400 gal. per week of floor drainage from area wash down.)
| |
| * provide preliminary processing through the use of a strainer and filters
| |
| * concentrate nonvolatile and, to some extent, volatile radioactive liquid contaminants, through evaporation, with a minimum decontamination factor (D.F. = Ratio of specific activity in the bottoms and distillate) of 104, at a bottoms concentration of 12 percent by weight
| |
| * concentrate the residual contaminants (bottoms) up to 12 percent total dissolved solids for transfer to the waste solidification system
| |
| * produce up to 25 gpm of distillate from the evaporator and condenser (The distillate is demineralized (if necessary) and tested in the waste processing liquid waste test tank before disposal offsite.)
| |
| * maintain, during normal operation, the radioactivity content of liquid effluents from the Seabrook site within the concentration limits expressed in 10 CFR Part 20, Appendix B, Table II, Column 2, on an instantaneous release basis and on an annual average release basis to maintain the radioactive liquid effluents so that the dose guidelines expressed in the Appendix I to 10 CFR Part 50 are not exceeded
| |
| * provide processing equipment and capacity sufficient to maintain radioactivity in liquid effluents within the applicable flexibility provisions of Appendix I to 10 CFR Part 50 during anticipated operational occurrences 2.3.3.44.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the waste processing liquid system mechanical components within th e scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the waste processing liquid system mechanical components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.3.45 Waste Processing Liquid Drains System 2.3.3.45.1 Summary of Technical Information in the Application This system includes tanks, sumps, pumps, piping, and instrumentation, as required, to collect, segregate, and control liquid leakage within the radioactively contaminated portions of the plant. The equipment and floor drainage system (waste processing liquid drains system) is operable during all normal modes of operation. The entire system is classified as NNS, non
| |
| -seismic Category I, non
| |
| -Class 1E, with the exception of piping runs through the containment walls and the isolation valves for these penetrations.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-108 The system is designed to handle all anticipated normal leakage volumes from component and liquid drain sources within the area covered by the equipment and floor drainage system.
| |
| The system is also designed to handle all anticipated abnormal leakage from sources such as malfunctioning pump seals, leaky flange gaskets, and blown valve stem packing. The maximum expected flow rate into any one sump from all expected abnormal sources is less than the 50 gpm capacity of the sumps in areas containing safety class equipment. Abnormal flows from pipe breaks are not included in the system design.
| |
| 2.3.3.45.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.45, UFSAR Sections 9.3.3 and 9.3.2.2, UFSAR Tables 6.2-83 and 7.5
| |
| -1, and the license renewal boundary drawings using the evaluation methodology described in SER Section 2.3 and the guidance in SRP
| |
| -LR Section 2.3. The staff's review identified areas in which additional information was required to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAIs, as discussed below.
| |
| In RAI 2.3.3.45
| |
| -01, dated January 5, 2011 (ADAMS Accession No. ML103420583), the staff noted on LRA drawing PID WLD-LR20218, at location G
| |
| -6, that the applicant labels license renewal Note 2, which states "[c]omponents have an internal environment of air/gas so they have no license renewal
| |
| -intended function and are not in scope." The portion of the 2
| |
| -in. piping excluded from scope of license renewal is directly connected to the in
| |
| -scope reactor coolant drain tank and continues up to the relief valve V
| |
| -83. LRA Table 3.3.2
| |
| -45 does not list an internal environment of air or gas for tanks. The staff is concerned with conditions where the relief valves actuate and the piping is fluid filled during a DBE. The applicant was asked to do one of the following:
| |
| * include the piping attached to the reactor coolant drain tank within the scope of license renewal and subject to AMR in accordance with 10 CFR 54.4(a)(2)
| |
| * provide the results of an evaluation that demonstrates the failure of this piping, while fluid-filled during a DBE, will not prevent the satisfactory accomplishment of any functions identified in 10 CFR 54.4(a)(1)
| |
| In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant stated that the 2
| |
| -in. piping attached to the reactor coolant drain tank is excluded from the scope of license renewal since it contains air or gas during normal operation and would under extremely rare conditions contain drainage from the valve steam leak
| |
| -off lines. The applicant stated that its assessment of the reactor coolant drain tank is consistent with its scoping methodology found in LRA Section 2.1.2.2.3, which states that nonsafety
| |
| -related components containing air or gas are excluded from scope of license renewal with the exception of portions that are directly attached to safety
| |
| -related components and were required for structural support. For additional justification for excluding the drain tank, the applicant referenced NUREG-1800, Section A.1 (BTP RLSP
| |
| -1), which states specific aging effects from abnormal events need not be postulated for license renewal. The applicant determined that the internal environment of the 2
| |
| -in. piping is air
| |
| -indoor uncontrolled, and no credible aging effect could degrade the piping. However, during the April 8, 2011, teleconference between the applicant and the staff, the applicant revised its position on excluding the 2
| |
| -in. piping from the scope of license renewal. The applicant submitted supplemental information to the staff on
| |
| | |
| Structures and Components Subject to Aging Management Review 2-109 April 22, 2011 (ADAMS Accession No. ML11115A116), which include the 2
| |
| -in. piping within the scope of license renewal under 10 CFR 54.4(a)(2) for spatial interaction.
| |
| Based on its review, the staff finds the applicant's response to RAI 2.3.3.45
| |
| -01 acceptable because the applicant revised its position regarding the 2
| |
| -in. piping to include it within the scope of license renewal under 10 CFR 54.4(a)(2) for spatial interaction. Therefore, the staff's concern described in RAI 2.3.3.45
| |
| -01 is resolved.
| |
| In RAI 2.3.3.45
| |
| -02, dated January 5, 2011 (numbered as RAI 2.2.3.45
| |
| -02 in ADAMS Accession No. ML103420583), the staff noted on LRA drawing PID WLD-LR20218, at location H
| |
| -5, that the applicant depicts a relief valve tailpipe connected to relief valve V83 as not being within the scope of license renewal. However, on LRA drawing PID WLD-LR20219, at location F
| |
| -4, the applicant depicts the tailpipe within the scope of license renewal under 10 CFR 54.4(a)(2). The applicant was asked to clarify the scoping classification for the relief valve tailpipe.
| |
| In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant initially stated that the relief valve tailpipe connected to relief valve V83 is not within the scope of license renewal. The applicant also indicated that LRA drawing PID-1-WLD-LR20219 erroneously depicted the relief valve tailpipe as being within the scope of license renewal. However, during the April 8, 2011, teleconference between the applicant and the staff, the applicant revised its position on excluding the relief valve tailpipe from the scope of license renewal. The applicant submitted supplemental information to the staff by letter dated April 22, 2011 (ADAMS Accession No. ML11115A116), which included the relief valve tailpipes within the scope of license renewal under 10 CFR 54.4(a)(2) for spatial interaction.
| |
| Based on its review, the staff finds the applicant's response to RAI 2.3.3.45
| |
| -02 acceptable because the applicant revised its position regarding the relief valve tailpipe to include it within the scope of license renewal under 10 CFR 54.4(a)(2) for spatial interaction. Therefore, the staff's concern described in RAI 2.3.3.45
| |
| -02 is resolved.
| |
| 2.3.3.45.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI responses, and license renewal boundary drawings to determine whether the applicant had identified all components within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all components subject to an AMR. On the basis of its review, the staff concludes the applicant appropriately identified the waste processing liquid drains system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
| |
| | |
| ====2.3.4 Steam====
| |
| and Power Conversion Systems LRA Section 2.3.4 identifies the steam and power conversion systems SCs subject to an AMR for license renewal.
| |
| The applicant described the supporting SCs of the steam and power conversion systems in the following LRA sections:
| |
| | |
| Structures and Components Subject to Aging Management Review 2-110
| |
| * Section 2.3.4.1, "Auxiliary Steam (AS) System"
| |
| * Section 2.3.4.2, "Auxiliary Steam Condensate (ASC) System"
| |
| * Section 2.3.4.3, "Auxiliary Steam Heating (ASH) System"
| |
| * Section 2.3.4.4, "Circulating Water (CW) System"
| |
| * Section 2.3.4.5, "Condensate (CO) System"
| |
| * Section 2.3.4.6, "Feedwater (FW) System"
| |
| * Section 2.3.4.7, "Main Steam (MS) System (Includes Main Steam Drain System)"
| |
| * Section 2.3.4.8, "Steam Generator Blowdown (SB) System" The staff's findings on review of LRA Sections 2.3.4.1
| |
| -2.3.4.8 are in provided in SER Sections 2.3.4.1
| |
| -2.3.4.8, respectively. 2.3.4.1 Auxiliary Steam System 2.3.4.1.1 Summary of Technical Information in the Application The auxiliary steam system is comprised of the following equipment:
| |
| * two package boilers, each rated at 80,000 pounds (lb) per hour of saturated steam a t 150 psig, complete with forced draft fans, breeching, and common stack
| |
| * one 170,000 lb per hour de
| |
| -aerating heater with storage tank
| |
| * three motor
| |
| -driven boiler feed pumps rated at 180 gpm each (one spare)
| |
| * triplex fuel oil pumping set (one spare pump)
| |
| * one blowdown tank, one fuel oil storage tank, and two skid
| |
| -mounted chemical feed units
| |
| * interconnecting piping
| |
| * safety-related primary auxiliary building isolation valves During plant start
| |
| -up, excess condensate from auxiliary steam used for turbine gland sealing and shell warming is returned to the auxiliary steam condensate system.
| |
| Feedwater from the de
| |
| -aerator is pumped to the auxiliary boilers and evaporated. Steam is piped to building heating units and operating equipment. Building heating system condensate and the equipment steam or drains, or both, are added to the main cycle or returned to the auxiliary boiler de
| |
| -aerator. The boilers are fired by No. 2 fuel oil. Steam atomization is used during normal boiler operation. Air is the atomizing medium for startup.
| |
| During normal plant operation, a branch line from main steam system lines can supply the required steam to the auxiliary steam system. A pressure
| |
| -reducing valve reduces the main steam pressure to that equivalent to the output of the auxiliary boilers. The pressure
| |
| -reducing station is closed during station startup, when the auxiliary boilers furnish the required steam. The auxiliary steam primary auxiliary building isolation valves are operable from the main control board and close automatically on an HELB signal.
| |
| 2.3.4.1.2 Conclusion
| |
| | |
| Structures and Components Subject to Aging Management Review 2-111 Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the auxiliary steam system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the auxiliary steam system mechanical components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.4.2 Auxiliary Steam Condensate System 2.3.4.2.1 Summary of Technical Information in the Application The auxiliary steam condensate system is part of the auxiliary steam system, as described in UFSAR Section 10.4.11. During plant start
| |
| -up, excess condensate from auxiliary steam
| |
| -used for turbine gland sealing and shell warming
| |
| -is returned to the auxiliary steam condensate system. During normal operation, building heating system condensate and the equipment steam or drains, or both, are added to the main cycle or returned to the auxiliary boiler de
| |
| -aerator. In the event that any of the systems being supplied with auxiliary steam become contaminated, the auxiliary condensate will, in turn, become contaminated. To prevent the auxiliary boiler from becoming contaminated, the unit is equipped with a radiation monitor, which samples the condensate in the condensate return line. If the radionuclide concentration exceeds a pre
| |
| -selected level, the monitor automatically terminates the condensate return.
| |
| 2.3.4.2.2 Staff Evaluation The staff reviewed LRA Section 2.3.4.2, UFSAR Section 10.4.11, and the license renewal boundary drawings using the evaluation methodology described in SER Section 2.3 and the guidance in SRP
| |
| -LR Section 2.3. In addition to the continuation issue identified in RAI 2.3
| |
| -01 described in Section 2.3.3, the staff's review identified an area in which additional information was required to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAI, as discussed below. In RAI 2.3.4.2
| |
| -01, dated January 5, 2011 (numbered as RAI 2.2.3.45
| |
| -02 in ADAMS Accession No. ML103420583), the staff noted on LRA drawing PID ASC-LR20908, at location E
| |
| -12, that the applicant depicts piping inside heat exchanger HWS
| |
| -E-132 within the scope of license renewal under 10 CFR 54.4(a)(2). However, on LRA drawing PID HW-LR20056, at location F
| |
| -11, the applicant depicts the same piping for the heat exchanger HWS
| |
| -E-132 not within the scope of license renewal. The applicant was asked to clarify the scoping of the piping inside the heat exchanger HWS
| |
| -E-132. In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant stated the piping (or tubing) inside the heat exchanger HWS
| |
| -E-132 is excluded from within the scope of license renewal. The applicant also indicated that the LRA drawing erroneously depicted the tubing as being within the scope of license renewal.
| |
| Based on its review, the staff finds the applicant's response to RAI 2.3.4.2
| |
| -01 acceptable because the applicant clarified that the piping inside the heat exchanger is not in the scope of license renewal. The staff confirmed this to be acceptable by reviewing LRA Section 2.3.3.19, "Hot Water Heating System," and confirming that the heat exchanger is in
| |
| -scope for pressure Structures and Components Subject to Aging Management Review 2-112 boundary and the tubing inside the heat exchanger was not listed in the scope of license renewal. Therefore, the staff's concern described in RAI 2.3.4.2
| |
| -01 is resolved.
| |
| 2.3.4.2.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI responses, and license renewal boundary drawings to determine whether the applicant had identified all components within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all components subject to an AMR. On the basis of its review, the staff concludes the applicant appropriately identified the auxiliary steam condensate system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
| |
| 2.3.4.3 Auxiliary Steam Heating System 2.3.4.3.1 Summary of Technical Information in the Application The auxiliary steam heating system provides low
| |
| -pressure, saturated steam to various plant equipment and buildings for heating purposes.
| |
| 2.3.4.3.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the auxiliary steam heating system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the auxiliary steam heating system mechanical components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.3.4.4 Circulating Water System 2.3.4.4.1 Summary of Technical Information in the Application The circulating water system provides cooling water to the main condensers to remove the heat rejected by the turbine cycle and auxiliary systems. The design of the system also includes the capability for furnishing cooling water to the service water system and returning it to the circulating water discharge flow. Cooling and lubricating water for the circulating water pumps and motors is provided by the discharge of the operating pumps. On the startup of the first circulating water pump, the service water screen wash system pump provides the water source. 2.3.4.4.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and license renewal boundary drawings, the staff concluded that the applicant appropriately identified the circulating water system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the circulating water system mechanical components subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| | |
| Structures and Components Subject to Aging Management Review 2-113 2.3.4.5 Condensate System 2.3.4.5.1 Summary of Technical Information in the Application The condensate system, in conjunction with the feedwater system, returns the condensate from the turbine condenser hotwells through the regenerative feed heating cycle to the steam generators while maintaining the water inventories throughout the cycle.
| |
| Three motor
| |
| -driven, constant
| |
| -speed, vertical canned
| |
| -type condensate pumps withdraw condensate from the three condenser hotwells. During normal operation, only two pumps will be operating, and one will be on standby. Seal and priming water are supplied to the condensate pumps from the condensate storage tank or the demineralized water system. The condensate pumps discharge into a common header that carries the flow to the steam packing exhauster, which condenses the turbine sealing steam and exhausts noncondensibles through blowers to the atmosphere. The common condensate header distributes the flow equally to the suction side of the two steam generator feed pumps.
| |
| Condenser hot well makeup is provided from either the condensate storage tank or the demineralized water storage tanks upon receipt of a hotwell low
| |
| -level signal. The condensate storage tank is protected from freezing by a recirculation system, which uses a heat exchanger and pump controlled by tank temperature. All condensate system connections to the condensate storage tank, which are required for normal system operation, are located above the tank level required for emergency plant shutdown. The bottom half of the tank (212,000 gal.) is used only for emergency plant shutdown and cooldown by the emergency feedwater pumps. The EFW system is evaluated under the feedwater system.
| |
| A steam generator startup feed pump provides normal requirements for startup, cooldown, and no-load operation. The pump takes suction from the condensate storage tank and discharges through a startup heater into the high pressure feedwater heater discharge piping. The startup feedwater system is evaluated under the feedwater system. The condensate pumps can also be used for startup by using the steam generator feedwater pump bypass piping.
| |
| 2.3.4.5.2 Staff Evaluation The staff reviewed LRA Section 2.3.4.5, UFSAR Sections 6.8.2, 9.2.6, 10.4.7, UFSAR Table 7.4-1, and the license renewal boundary drawings using the evaluation methodology described in SER Section 2.3 and the guidance in SRP
| |
| -LR Section 2.3. The staff's review identified an area in which additional information was required to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAI, as discussed below. In RAI 2.3.4.5
| |
| -01, dated January 5, 2011 (numbered as RAI 2.2.3.45
| |
| -02 in ADAMS Accession No. ML103420583), the staff noted on LRA drawing PID CO-LR20426, at location H
| |
| -9, that the applicant depicts a floating seal in the condensate storage tank as not being within scope of license renewal. However, LRA Table 2.3.4
| |
| -5 does not list this floating seal. The staff also noted that the floating seal appears to be part of the condensate system tank, which is depicted as being within the scope of license renewal under 10 CFR 54.4(a)(1). Therefore, the staff requested that the applicant justify the exclusion of the floating seal from the scope of license renewal and LRA Table 2.3.4
| |
| -5.
| |
| Structures and Components Subject to Aging Management Review 2-114 In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant stated the floating cover seal was included within scope of license renewal under 10 CFR 54.4(a)(2) for providing functional support for the condensate storage tank. However, the applicant excluded the floating seal from being subject to an AMR due to the floating seal being replaced every six refueling cycles.
| |
| Based on its review, the staff finds the applicant's response to RAI 2.3.4.5
| |
| -01 acceptable because the floating seal was included within scope of license renewal under 10 CFR 54.4(a)(2) due to its functional support for the condensate storage tank. The staff confirmed that the applicant's justification for exempting the floating seal from an AMR is consistent with 10 CFR 54.21(a)(1)(ii) due to the floating seal being replaced every six refueling cycles. Therefore, the staff's concern described in RAI 2.3.4.5
| |
| -01 is resolved.
| |
| 2.3.4.5.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI response, and license renewal boundary drawings to determine whether the applicant had identified all components within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all components subject to an AMR. On the basis of its review, the staff concludes the applicant appropriately identified the condensate system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
| |
| 2.3.4.6 Feedwater System 2.3.4.6.1 Summary of Technical Information in the Application The feedwater system receives water from the condensate system and a portion of the heater drain system (specifically, drains from high pressure heaters No. 6, low pressure heaters No. 5, moisture separator reheater shell drains, and moisture separator reheater drains). The feedwater is pumped through the final stage of feedwater heaters (high pressure heaters No. 6) to the four steam generators.
| |
| The four feedwater lines exit the turbine building; two routed east of the containment and two routed west, where they enter the east and west main steam and feedwater pipe chases. The east and west pipe chases house the feedwater isolation valves, which are located just upstream of the containment penetrations and connections to the steam generators. Immediately upstream of the feedwater isolation valve is a check valve and a flow measuring device. The EFW pump discharge connection to each main feedwater line is located between the containment penetration and the feedwater isolation valve.
| |
| An ultrasonic feedwater flow measurement system is installed in the common feedwater header, just upstream of the feedwater regulating valves. This system comprises a 36
| |
| -in. in-line flow measurement spool piece and a local system processor panel. The ultrasonic flow measurement system provides high accuracy mass flow, feedwater temperature, and feedwater pressure signals to the main plant computer system via a digital communication link. These signals are used as inputs to the secondary power calorimetric calculation performed by the main plant computer system.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-115 Each steam generator feedwater pump has a recirculation control system, which protects the pumps from damage at low loads by ensuring minimum flow. A feed pump gland seal water system regulates the flow of condensate from the condensate pump discharge header to the feed pump seals. Leak
| |
| -off from the seals to the seal water receiver tank is returned to the condenser using a tank level controller, which operates a control valve in the outlet line from the tank to the condenser.
| |
| Individual steam turbines drive the steam generator feedwater pumps. The turbine drives are of the dual admission type, and each is equipped with two sets of stop and control valves. One set regulates high
| |
| -pressure steam from the main steam system, and the other set regulates low
| |
| -pressure steam extracted from the crossover piping. Gland steam is provided to the turbines from the main turbine gland steam supply system. The exhaust steam from the steam generator feedwater pump turbine drives is condensed in main condenser shells "A" and "C." One steam generator startup feed pump provides normal requirements for startup, cooldown, and no-load operation. The pump takes suction from the condensate storage tank and discharges through a startup heater into the high
| |
| -pressure feedwater heater discharge piping. The pump suction may also be aligned to the demineralized water storage tanks as a backup water source. Startup feedwater flow may also be directed through both high
| |
| -pressure feedwater heaters in series. The startup feedwater system is described in Subsection 10.4.12 of the UFSAR. The condensate pumps can also be used for startup by using the steam generator feedwater pump bypass piping. A sampling system is provided and connected to various points in the condensate, feedwater, and heater drains systems (see UFSAR Subsection 9.3.2).
| |
| Condensate and feedwater chemistry is controlled as described in UFSAR Subsection 10.3.5.
| |
| The chemical feed for the condensate and steam generator wet layup systems is stored in covered tanks for personnel protection.
| |
| EFW System. Upon loss of normal feedwater flow, the reactor is tripped, and the decay and sensible heat is transferred to the steam generators by the RCS via the RCPs or by natural circulation when the pumps are not operational.
| |
| Heat is removed from the steam generators via the main condensers or the main steam safety or steam generator atmospheric relief valves. Steam generator water inventory is maintained by water makeup from the EFW system.
| |
| The system will supply feedwater to the steam generators to remove sufficient heat to prevent the over
| |
| -pressurization of the RCS and to allow for eventual system cooldown.
| |
| The EFW system comprises two full
| |
| -sized pumps (one motor and one turbine driven) whose water source is the condensate storage tank. Suction lines are individually run from the condensate storage tank to each pump. A common EFW pump recirculation line discharges back to the condensate storage tank. This return line functions for recirculation pump testing and ensures minimum flow to prevent pump damage for any system low
| |
| -flow operating condition. Both pumps feed a common discharge header, which, in turn, supplies the four emergency feed lines. The common discharge header includes normally open gate valves between each branch connection to provide isolation in the event of a pipe break or for maintenance. Each emergency feed line is connected to one of the main feedwater lines Structures and Components Subject to Aging Management Review 2-116 downstream of the feedwater isolation valve. Each main feedwater line enters the containment through a single penetration and feeds a single steam generator.
| |
| Additional redundant pumping capability is provided by the startup feed pump in the feedwater system. A dedicated 196,000 gal. of demineralized water is maintained in the lower half of the condensate storage tank for the exclusive use of the EFW system.
| |
| The branch lines to each steam generator include a manual gate isolation valve, two motor
| |
| -operated flow control valves, a flow venturi, and a flow orifice. The flow control valves are normally in the open position when the system is not operating, and they are automatically closed during system operation in the event of a pipe break. These valves can be operated remotely, as described in UFSAR Subsection 6.8.5, to control steam generator water level. Two valves in series are provided for redundancy and are powered from different trains. Each valve is also provided with a hand wheel to permit manual operation. The open position of the flow control valves for system limiting conditions is set to insure the minimum required flow of 470 gpm to three steam generators and a minimum total flow of 650 gpm to four steam generators with one EFW pump operational.
| |
| 2.3.4.6.2 Staff Evaluation The staff reviewed LRA Section 2.3.4.6, UFSAR Sections 6.8, 9.3.2, 10.3.5, 10.4.7, 10.4.12, UFSAR Tables 7.4
| |
| -1, 7.5-1, and 6.2
| |
| -83, and the license renewal boundary drawings using the evaluation methodology described in SER Section 2.3 and the guidance in SRP
| |
| -LR Section 2.3.
| |
| The staff's review identified an area in which additional information was required to complete the review of the applicant's scoping and screening results related to the drawings' location of continuation of piping in scope of license renewal. The staff addressed the applicant's response to RAI 2.3
| |
| -01 (ADAMS Accession No. ML110380081) in Section 2.3.3 of this SER. The staff did not identify any additional concerns with the applicant's scoping and screening of feedwater system components for license renewal. 2.3.4.6.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI response, and license renewal boundary drawings to determine whether the applicant had identified all components within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all components subject to an AMR. On the basis of its review, the staff concludes the applicant appropriately identified the feedwater system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
| |
| 2.3.4.7 Main Steam System (Includes Main Steam Drain System) 2.3.4.7.1 Summary of Technical Information in the Application
| |
| | |
| Structures and Components Subject to Aging Management Review 2-117 The major function of the main steam system is to transport the steam generated in the four steam generators to the turbine generator for conversion to electrical power. Heat transferred from the reactor core to the RCS is subsequently transferred across the steam generator U
| |
| -tubes for conversion of secondary feedwater into main steam.
| |
| This steam passes through a moisture separator and a flow restrictor as it leaves the steam generator and enters its main steam header. The moisture separator improves steam quality, while the flow restrictor prevents excessive steam flow in the event of an unisolable steam line rupture. 2.3.4.7.2 Staff Evaluation The staff reviewed LRA Section 2.3.4.7, UFSAR Section 10.3, UFSAR Tables 6.2
| |
| -83, 7.4-1, and 7.5-1, and the license renewal boundary drawings using the evaluation methodology described in SER Section 2.3 and the guidance in SRP
| |
| -LR Section 2.3. The staff's review identified an area in which additional information was required to complete the review of the applicant's scoping and screening results related to the drawings' location of continuation of piping in scope of license renewal. The staff addressed the applicant's response to RAI 2.3
| |
| -01 (ADAMS Accession No. ML110380081) in Section 2.3.3 of this SER. The staff did not identify any additional concerns with the applicant's scoping and screening of main steam system components for license renewal.
| |
| 2.3.4.7.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI response, and license renewal boundary drawings to determine whether the applicant had identified all components within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all components subject to an AMR. On the basis of its review, the staff concludes the applicant appropriately identified the main steam system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
| |
| 2.3.4.8 Steam Generator Blowdown System 2.3.4.8.1 Summary of Technical Information in the Application Each of the four steam generators is provided with a bottom blow down connection on the secondary side above the tube sheet. During normal operation, each steam generator undergoes continuous blowdown with the blowdown water passing through a containment isolation valve, flow meter, and system valves. A small quantity of blowdown is continuously drawn off automatically into the sample system through a sample heat exchanger for monitoring the activity in the blowdown. If the activity in the blow down discharge is higher than allowable, blowdown is automatically secured. The blowdown liquid then flows through a manual control valve, which establishes the blowdown rate. Some of the liquid flashes upon passing through the control valve, and two
| |
| -phase flow then enters the flash tank. There, approximately 30 percent of the blowdown flow exits the top of the tank as saturated steam. The remaining 70 percent exits the bottom of the tank as saturated water.
| |
| 2.3.4.8.2 Staff Evaluation
| |
| | |
| Structures and Components Subject to Aging Management Review 2-118 The staff reviewed LRA Section 2.3.4.8, UFSAR Section 10.4.8, UFSAR Tables 6.2
| |
| -83, 7.4-1, and 7.5-1, and the license renewal boundary drawings using the evaluation methodology described in SER Section 2.3 and the guidance in SRP
| |
| -LR Section 2.3. In addition to the continuation issue identified in RAI 2.3
| |
| -01 described in Section 2.3.3, the staff's review identified an area in which additional information was required to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAI, as discussed below.
| |
| In RAI 2.3.4.8
| |
| -01, dated January 5, 2011 (numbered as RAI 2.2.3.45
| |
| -02 in ADAMS Accession No. ML103420583), the staff noted on LRA drawing PID SS-LR20521, at location A
| |
| -6, that the applicant depicts cooler H
| |
| -376 as being within the scope of license renewal under 10 CFR 54.4(a)(2). However, the applicant excludes the "vent to atmosphere" piping, which is attached to cooler H
| |
| -376, from the scope of license renewal. The applicant was asked to justify its exclusion of the "vent to atmosphere" piping from the scope of license renewal. In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant stated the "vent to atmosphere" piping is within the scope of license renewal under 10 CFR 54.4(a)(2). The applicant also stated that LRA drawing PID SS-LR20521 erroneously depicted the "vent to atmosphere" piping as being excluded from the scope of license renewal.
| |
| Based on its review, the staff finds the applicant's response to RAI 2.3.4.8
| |
| -01 acceptable because the "vent to atmosphere" piping was already included within the scope of license renewal under 10 CFR 54.4(a)(2). Therefore, the staff's concern described in RAI 2.3.4.8
| |
| -01 is resolved.
| |
| 2.3.4.8.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI responses, and license renewal boundary drawings to determine whether the applicant had identified all components within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all components subject to an AMR. On the basis of its review, the staff concludes the applicant appropriately identified the steam generator blowdown system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
| |
| | |
| ===2.4 Scoping===
| |
| and Screening Results: Structures This section documents the staff's review of the applicant's scoping and screening results for structures. Specifically, this section discusses the reactor building and other Class I and in
| |
| -scope structures.
| |
| In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, long-lived SCs within the scope of license renewal and subject to an AMR. To verify that the applicant properly implemented its methodology, the staff's review focused on the implementation results. This focus allowed the staff to confirm that there were no omissions of SCs that meet the scoping criteria and are subject to an AMR.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-119 The staff's evaluation of the information in the LRA was the same for all structures. The objective was to determine if the applicant identified, in accordance with 10 CFR 54.4, components and supporting structures for structures that appear to meet the license renewal scoping criteria. Similarly, the staff evaluated the applicant's screening results to verify that all passive, long
| |
| -lived SCs were subject to an AMR in accordance with 10 CFR 54.21(a)(1).
| |
| In its scoping evaluation, the staff reviewed the applicable LRA sections, focusing on components that have not been identified as within the scope of license renewal. The staff reviewed relevant licensing basis documents, including the UFSAR, for each structure to determine if the applicant omitted from the scope of license renewal components with intended functions delineated under 10 CFR 54.4(a). The staff also reviewed the licensing basis documents to determine if the LRA specified all intended functions delineated under 10 CFR 54.4(a). The staff requested additional information to resolve any omissions or discrepancies identified.
| |
| After its review of the scoping results, the staff evaluated the applicant's screening results. For those SCs with safety
| |
| -related intended functions, the staff sought to determine if the functions are performed with moving parts or a change in configuration or properties or if the SCs are subject to replacement after a qualified life or specified time period, as described in 10 CFR 54.21(a)(1). For those meeting neither of these criteria, the staff sought to confirm that these SCs were subject to an AMR, as required by 10 CFR 54.21(a)(1). The staff requested additional information to resolve any omissions or discrepancies identified.
| |
| 2.4.1 Buildings, Structures within License Renewal 2.4.1.1 Summary of Technical Information in the Application In LRA Section 2.4.1, the applicant described the buildings and structures within license renewal as being NNS
| |
| -related, miscellaneous buildings that could prevent satisfactory accomplishment of a safety
| |
| -related 10 CFR 54.4(a)(1) function. In addition, these structures and buildings may house equipment for any of the 10 CFR 54.4(a)(3) regulated events. The following structures are described in LRA Section 2.4.1.
| |
| Discharge Transition Structure. This Non
| |
| -Seismic Category I structure provides a path to discharge cooling water from the condenser through the discharge tunnel and into the ocean during normal operation. The structure is also aligned to provide water from the discharge tunnel to the service water pumphouse and the circulating water pumphouse if necessary.
| |
| Fire Pumphouse (including Fire Protection Water Storage Tanks (foundations only), Fire Pumphouse Boiler Building, Boiler Fuel Tank (foundation and steel framing only), and two Fuel Oil Day Tanks (foundations and steel framing only). The fire pumphouse is a non
| |
| -seismic Category I structure that houses electric and diesel
| |
| -driven fire pumps and associated controls.
| |
| The two 500,000 gal. fire protection water storage tanks are non
| |
| -seismic Category I structures. The fire pumphouse boiler building and boiler fuel tank are non
| |
| -seismic Category I structures. The purpose of the boiler is to provide heat to the fire pumphouse. In addition, two fuel oil day tanks provide diesel fuel to the two diesel
| |
| -driven fire pumps.
| |
| Intake Transition Structure. This non-seismic Category I structure provides seawater to the service water pumphouse and the circulating water pumphouse from the ocean and intake tunnel. In addition, it serves as a surge chamber that stabilizes changing water levels.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-120 Non-Essential Switchgear Building. This non
| |
| -seismic Category I structure houses Appendix R emergency lighting needed for operation of safe shutdown equipment and for access and egress routes thereto. In addition, it houses and protects the electrical equipment used to provide lighting for the plant.
| |
| Revetment. The revetment structures are classified as non
| |
| -seismic Category I and provide flood protection to safety
| |
| -related structures from a predicted probable maximum hurricane surge by means of a protective retaining wall, a vertical seawall, and revetment (riprap).
| |
| Steam Generator Blowdown Recovery Building. The steam generator blowdown recovery building is a non
| |
| -seismic Category I structure and houses the steam generator blowdown recovery system. The loss of function of these systems and components will not affect the capability of a safe reactor shutdown.
| |
| LRA Table 2.4
| |
| -1 identifies the components subject to an AMR, for the buildings and structures within license renewal, by component type and intended function.
| |
| 2.4.1.2 Staff Evaluation The staff reviewed LRA Section 2.4.1 and the UFSAR using the evaluation methodology described in SER Section 2.4 and the guidance in SRP
| |
| -LR Section 2.4.
| |
| During its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any SCs with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those SCs that the applicant has included as within the scope of license renewal to verify that the applicant has not omitted any passive and long
| |
| -lived SCs subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).
| |
| During its review of LRA Section 2.4, the staff noted areas in which additional information was necessary to complete its review of the applicant's scoping and screening results. Specifically, the staff noted that there were no trash racks, basket strainers, traveling screens, or any other debris prevention or removing mechanisms listed as part of the intake transition structure. By letter dated November 18, 2010 (ADAMS Accession No. ML103090308), the staff issued RAI 2.4.1-1, requesting that the applicant verify if the aforementioned components are present and within the scope of license renewal of the identified structure and, thus, subject to an AMR. In addition, if they are subject to an AMR, the staff asked that the applicant identify the applicable aging effects and the AMP related to these components.
| |
| By letter dated December 3, 2010 (ADAMS Accession No. ML103400259), the applicant responded to RAI 2.4.1
| |
| -1 and stated the following:
| |
| There, are no structural components such as trash racks, basket strainers, traveling screens or any other debris prevention/removing mechanisms that are part of the Intake Transition Structure.
| |
| There is a Chlorination System (CL) Strainer, 1
| |
| -CL-S-256, which is located in a pit, adjacent to the Intake Transition Structure that is in scope for license renewal. Being non
| |
| -metallic and having no reported aging effects, the strainer does not require an aging management program.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-121 The Service Water Pumphouse does contain traveling screens. These were screened out of License Renewal as being active components, except for the covering shrouds, which are in
| |
| -scope with an (a)(2) intended function of protecting safety related equipment from raw water spray. The shrouds are fiberglass, with no aging effects, and are not age managed.
| |
| Located in the Primary Auxiliary Building, a basket
| |
| -type strainer is provided i n each train of the, Service Water System to prevent shells and mussels, which could be carried into these lines, from fouling various heat exchangers. These strainers are within the scope of License Renewal and are age managed as part of the Open Cycle Cooling Water Aging Management Program.
| |
| In reviewing the applicant's response to RAI 2.4.1
| |
| -1, the staff found that the applicant adequately clarified the location of the trash racks, basket strainers, traveling screens, or any other debris prevention or removing mechanisms present. Additionally, for those present and within the scope of license renewal, an AMP was in place to manage the age effects of the component. Based on its review, the staff finds the applicant's response to RAI 2.4.1
| |
| -1 acceptable because it clarified that there are no trash racks, basket strainers, traveling screens, or any other debris prevention or removing mechanisms in the intake transition structure within the scope of license renewal and subject to an AMR. The staff's concern described in RAI 2.4.1
| |
| -1 is resolved.
| |
| By letter dated November 18, 2010 (ADAMS Accession No. ML103090308), the staff issued RAI 2.4.1-2 asking that the applicant provide additional information regarding the fire protection water storage tanks. Specifically, the staff sought to determine if there was any steel framing that was part of the structural arrangement of the tanks, since only the foundation was included in the scope of license renewal.
| |
| * rolling steel door in the Fuel Storage Building (elevation 20 ft 6 in. mean sea level (MSL))
| |
| * double doors into the entrance vestibule of the Equipment Vault section of the Primary Auxiliary Building (elevation 20 ft 8 in. MSL)
| |
| For those components that should be included within the scope of license renewal, the staff also asked the applicant to detail the applicable aging effects and the appropriate AMP related to the component.
| |
| By letter dated December 3, 2010 (ADAMS Accession No. ML103400259), the applicant responded to RAI 2.4.1
| |
| -2 and stated, in part, that "[f]lood protection for the Fuel Storage Building is provided by a curb at elevation 21.5 ft MSL located on column 3 behind the rolling steel door-"
| |
| The floor of the vestibule into the Equipment Vault section of the Primary Auxiliary Building is sloped up 4 in. so that the high point in the floor is at elevation 21 ft MSL.
| |
| Both doors are in scope of license renewal for intended functions other than flood protection.
| |
| The Fuel Storage Building rollup door is included in the generic component Primary Structures (PST)-Carbon Steel Door
| |
| -Fuel Storage Building in LRA Table 3.5.2
| |
| -5 and the double doors Structures and Components Subject to Aging Management Review 2-122 into the Equipment Vault are included in the generic component PST
| |
| -Carbon Steel Door
| |
| -Primary Auxiliary Building in LRA Table 3.5.2
| |
| -5. In reviewing the applicant's response to RAI 2.4.1
| |
| -2, the staff found that the applicant clarified the inclusion of the following components from the scope of license renewal:
| |
| * rolling steel door in the Fuel Storage Building (elevation 20 ft 6 in. MSL)
| |
| * double doors into the entrance vestibule of the Equipment Vault section of the Primary Auxiliary Building (elevation 20 ft 8 in. MSL)
| |
| Both doors are within the scope of license renewal for intended functions other than flood protection, and the applicant adequately described the flood protection mechanisms for the two access openings in the exterior wall that are below the design flood level. Based on its review, the staff finds the applicant's response to RAI 2.4.1
| |
| -2 acceptable because it clarified that (a) the rolling steel door in the Fuel Storage Building and (b) the double doors into the entrance vestibule of the Equipment Vault section of the Primary Auxiliary Building are not credited for flood protection. However, they are included in the scope of license renewal for other intended functions. Therefore, the staff's concern described in RAI 2.4.1
| |
| -2 is resolved.
| |
| By letter dated November 18, 2010 (ADAMS Accession No. ML103090308), the staff issued RAI 2.4.1-3 asking that the applicant provide additional information regarding the fire protection water storage tanks. Specifically, the staff sought to determine if there was any steel framing that was part of the structural arrangement of the tanks, since only the foundation was included in the scope of license renewal.
| |
| By letter dated December 3, 2010 (ADAMS Accession No. ML103400259), the applicant responded to RAI 2.4.1
| |
| -3 and stated that the fire protection water storage tanks are bolted to the tanks' foundation, are free
| |
| -standing, and have no supports.
| |
| In reviewing the applicant's response to RAI 2.4.1
| |
| -3, the staff found that the applicant clarified the structural configuration of the fire protection water storage tanks since they are free
| |
| -standing and have no support (i.e., structural steel framing). Based on its review, the staff finds the applicant's response to RAI 2.4.1
| |
| -3 acceptable because the structural configuration of the fire protection water storage tanks has been included in the scope of license renewal and subsequent AMP. The staff's concern described in RAI 2.4.1
| |
| -3 is resolved 2.4.1.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI response to determine whether the applicant had identified all SCs within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all SCs subject to an AMR. On the basis of its review, the staff concludes the applicant has adequately identified the buildings and structures SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| | |
| Structures and Components Subject to Aging Management Review 2-123 2.4.2 Containment Structures 2.4.2.1 Summary of Technical Information in the Application In LRA Section 2.4.2, the applicant described the containment structures as seismic Category I structures that enclose and provide physical support and protection to the RCS. The containment structures consist of the following structures.
| |
| Containment Structure. This reinforced concrete containment structure completely encloses the RCS and has the form of a right vertical cylinder with a hemispherical dome and a fla t foundation mat founded on bedrock. The inside face is lined with a welded carbon steel plate that provides a high degree of leak tightness. Containment penetrations are provided in the lower portion and consist of a personnel lock; an equipment hatch and personnel lock; a fuel transfer tube; and piping, electrical, instrumentation, and ventilation penetrations. All penetrations are anchored to sleeves embedded in the concrete wall.
| |
| Containment Enclosure Building. This reinforced concrete structure (containment enclosure building) surrounds the containment structure and is designed in a similar configuration as a vertical right cylinder with a dome and a ring base. The structure is designed to entrap, filter, and then discharge any leakage from the containment structure. The containment enclosure building provides the secondary containment barrier.
| |
| Containment Enclosure and Ventilation Area. This reinforced concrete structure is an irregularly shaped building that houses ventilation equipment such as fans and filters for the enclosure building. It is physically located on the southwest side of the containment.
| |
| Containment Internals. The containment internals consist of intermediate floor slabs, internal walls, steel framing, and other support appurtenances. The purpose of the containment internal structures is to provide structural support for safety and nonsafety
| |
| -related equipment, shielding, and HELB protection.
| |
| LRA Table 2.4
| |
| -2 identifies the components subject to an AMR for the containment structures within license renewal, by component type and intended function.
| |
| 2.4.2.2 Conclusion The staff reviewed the LRA and UFSAR to determine whether the applicant had identified all SCs within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all SCs subject to an AMR. On the basis of its review, the staff concludes that the applicant has adequately identified SCs (the containment structures) within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| 2.4.3 Fuel Handling and Overhead Cranes 2.4.3.1 Summary of Technical Information in the Application In LRA Section 2.4.3, the applicant described the fuel handling and overhead cranes as consisting of overhead heavy load cranes encompassed by NUREG
| |
| -0612, "Control of Heavy Loads at Nuclear Power Plants: Resolution of Generic Technical Activity A
| |
| -36," and light load Structures and Components Subject to Aging Management Review 2-124 cranes related to refueling handling systems. These systems are associated with reactor vessel assembly, fuel movement, spent fuel cask, and other overhead lifting activities that could have an effect on safe shutdown equipment or fuel integrity or both. LRA Table 2.4
| |
| -3 identifies the components subject to an AMR for the fuel handling and overhead cranes by component type and intended function.
| |
| 2.4.3.2 Conclusion The staff reviewed the LRA and UFSAR to determine whether the applicant had identified all SCs within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all SCs subject to an AMR. On the basis of its review, the staff concludes that the applicant has adequately identified the fuel handling and overhead cranes SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| | |
| ====2.4.4 Miscellaneous====
| |
| Yard Structures 2.4.4.1 Summary of Technical Information in the Application In LRA Section 2.4.4, the applicant described the miscellaneous yard structures as non
| |
| -building structures that are exposed to an outdoor environment. These structures include buried vaults, duct banks and manholes, the condensate storage tank enclosure, and SBO structures. They are described below in more detail.
| |
| Condensate Storage Tank Enclosure. The seismic Category I enclosure consists of a cylindrical reinforced concrete wall that surrounds the condensate storage tank. In addition, two irregularly shaped rooms
| |
| -north and south valve rooms
| |
| -are integral with the circular wall.
| |
| Control Room Makeup Air Intake Structures. The seismic Category I air intake structures serve as terminals for buried ductwork that provide air for the control rooms during accident conditions.
| |
| Nonsafety-Related Electrical Duct Banks and Manholes. The reinforced concrete manholes and nonsafety
| |
| -related electrical duct banks house select cables that support fire pump 1
| |
| -FP-P21. Safety-Related Electrical Duct Banks and Manholes
| |
| . The safety
| |
| -related electrical duct banks and manholes are made of reinforced concrete and are isolated by seismic joints.
| |
| Service Water Access Vault. The seismic Category I service water access vault is physically located underground north of the plant's cooling towers. This structure provides access to 24
| |
| -in. service water piping.
| |
| Yard Structures that Support Coping with SBO. The yard structures are described as providing equipment enclosure and structural support that ultimately supports SCs coping with an SBO event.
| |
| LRA Table 2.4
| |
| -4 identifies the components subject to an AMR for the miscellaneous yard structures within license renewal, by component type and intended function.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-125 2.4.4.2 Conclusion The staff reviewed the LRA and UFSAR to determine whether the applicant had identified all SCs within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all SCs subject to an AMR. On the basis of its review, the staff concludes that the applicant has adequately identified the SCs (miscellaneous yard structures) within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| | |
| ====2.4.5 Primary====
| |
| Structures 2.4.5.1 Summary of Technical Information in the Application In LRA Section 2.4.5, the applicant described the primary structures as being seismic Category I structures that are not part of the containment structures or water control structures. They consist of the following structures.
| |
| Containment Equipment Hatch Missile Shield. This structure consists of a removable, precast, reinforced concrete wall physically located outside the equipment hatch. The shield protects the hatch from tornado
| |
| -generated missiles.
| |
| Control Building and Diesel Generator Building. This structure is separated by a common wall in the north
| |
| -south direction and is made of reinforced concrete founded on fill concrete and rock below grade. The multi
| |
| -function structure consists of the east portion occupied by the control room and the west portion occupied by the diesel generator building.
| |
| EFPH including Electrical Cable Tunnels and Penetration Area (Control Building to Containment) and Pre
| |
| -Action Valve Building. The EFPH is physically located adjacent to the containment structure and consists of the EFW pump room located above a two
| |
| -story high electrical cable tray tunnel.
| |
| The pre-action valve room contains the deluge valve for the fire protection system and is located on the east side of the EFW building.
| |
| Fuel Storage Building. The spent fuel pool and storage facility consists of four main areas
| |
| -the spent fuel pool, the fuel transfer canal, the spent fuel cask loading area, and a decontamination area. The spent fuel pool is constructed of reinforced concrete, with all interior surfaces lined with stainless steel.
| |
| Main Steam and Feedwater Pipe Chases
| |
| -East and West. The main steam and feedwater pipe chases (east and west) are reinforced structures that house and protect the main steam and feedwater piping.
| |
| Personnel Hatch Area. The personnel hatch area is an irregularly shaped, reinforced concrete area that is physically located outside the personnel hatch of the containment and provides protection from missiles and illegal entry.
| |
| Primary Auxiliary Building including RH Equipment Vault. This building is a reinforced concrete structure that is physically located adjacent to the containment structure. The building houses most of the auxiliary systems for the RCS. In addition, it houses components essential for safe shutdown, which could be subject to the effects of an HELB.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-126 Tank Farm (Tunnels)
| |
| -Including Dikes and Foundations for RWST and Reactor Makeup Water Storage Tank. The tank farm areas consist of a reinforced concrete portion and structural steel framing portion. The reinforced portion is associated with safety
| |
| -related systems, and the steel portion is used to enclose the area above the tanks and to form the motor control center and switchgear room.
| |
| Waste Process Building. This building is a reinforced concrete structure that houses the liquid and gas waste processing, boron recovery, and solid waste systems. The building contains systems to process radioactive gases, liquids, and solids.
| |
| LRA Table 2.4
| |
| -5 identifies the components, subject to an AMR for the PSTs within license renewal, by component type and intended function.
| |
| 2.4.5.2 Conclusion The staff reviewed the LRA and UFSAR to determine whether the applicant had identified all SCs within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all SCs subject to an AMR. On the basis of its review, the staff concludes that the applicant has adequately identified the PSTs SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| | |
| ====2.4.6 Supports====
| |
| 2.4.6.1 Summary of Technical Information in the Application In LRA Section 2.4.6, the applicant described the supports commodity as including ASME and non-ASME pipe restraints and supports, jet impingement barriers and shields, pipe whip restraints, supports for tube tracks, instrument tubing, miscellaneous mechanical equipment, electrical raceways and conduit, HVAC ducts, racks, panels, cabinets, enclosures for electrical equipment, junction boxes, platforms, grout under base plates, fasteners and anchorage, instruments and battery racks, support base plate pads, etc. Supports provide the connection between a system's equipment or component and a plant structural member, such as a wall, beam, or column.
| |
| LRA Table 2.4
| |
| -6 identifies the components, subject to an AMR for the supports commodity within license renewal, by component type and intended function.
| |
| 2.4.6.2 Staff Evaluation The staff reviewed LRA Section 2.4.6 and the UFSAR using the evaluation methodology described in SER Section 2.4 and the guidance in SRP
| |
| -LR Section 2.4.
| |
| During its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant has not omitted from the scope of license renewal any SCs with intended functions delineated under 10 CFR 54.4(a).
| |
| The staff then reviewed those SCs that the applicant included as within the scope of license renewal to verify that the applicant has not omitted any passive and lon g-lived SCs subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).
| |
| | |
| Structures and Components Subject to Aging Management Review 2-127 During its review of LRA Section 2.6, the staff noted areas in which additional information was necessary to complete its review of the applicant's scoping and screening results. By letter dated November 18, 2010 (ADAMS Accession No. ML103090308), the staff issued RAI 2.4.6-1, requesting that the applicant confirm the inclusion of the structural bellows in the scope of license renewal, as applicable, and subject to an AMR, per 10 CFR 54.21(a)(1)(i), and provide the location in the LRA where they are covered. In addition, in the event that the structural bellows were omitted, the staff asked the applicant to justify the exclusion from the scope of license renewal.
| |
| By letter dated December 3, 2010 (ADAMS Accession No. ML103400259), the applicant responded to RAI 2.4.6
| |
| -1 and stated, in part, the following:
| |
| There are three structural bellows at Seabrook Station and all are associated with the fuel transfer tube between the fuel storage building and the containment structure. All three bellows are in scope of LR. One bellow in the fuel storage building is in scope as part of the fuel transfer tube component in the primary structures (Table 3.5.2
| |
| -5) and the other two bellows in the containment structure are located with the fuel transfer tube component in the containment structure (Table 3.5.2
| |
| -2). In reviewing its response to RAI 2.4.6
| |
| -1, the staff found that the applicant verified the inclusion of all structural bellows within the scope of license renewal. In addition, the response clarified the location within the LRA where the components were covered. Based on its review, the staff finds the applicant's response to RAI 2.4.6
| |
| -1 acceptable because the structural bellows at Seabrook have been included in the scope of license renewal and subsequent AMP. The staff's concern described in RAI 2.4.6
| |
| -1 is resolved.
| |
| By letter dated November 18, 2010 (ADAMS Accession No. ML103090308), the staff issued RAI 2.4.6-2, requesting that the applicant clarify a potential discrepancy regarding the neutron absorbent material attached to the spent fuel pool racks. Specifically, LRA Section 2.4.6 states that "BORAFLEX utilized in region 2 racks is not credited with the neutron
| |
| -absorbing capacity in the criticality analyses and therefore will not be managed for reduction of neutron absorbing capacity in the criticality analyses-" However, UFSAR Section 9.1.2.1 states that the "Region 2 Spent Fuel Racks contain BORAFLEX as a neutron absorbing material to assure a Keff<0.95." In addition, the staff asked that the applicant clearly state the inclusion, or justify the exclusion, of the BORAFLEX from the scope of license renewal and subject to an AMR. By letter dated December 3, 2010 (ADAMS Accession No. ML103400259), the applicant responded to RAI 2.4.6
| |
| -2 and stated, in part, the following:
| |
| An UFSAR change request has been issued to correct the inconsistency. The revised UFSAR will state that the BORAFLEX material is conservatively assumed to be neutron transparent based on industry experience of BORAFLEX degradation.
| |
| In reviewing the applicant's response to RAI 2.4.6
| |
| -2, the staff found that the applicant is aware of the inconsistency between references and has submitted a change request to reflect that BORAFLEX material will be conservatively assumed to be neutron transparent.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-128 Based on its review, the staff finds the applicant's response to RAI 2.4.6
| |
| -2 acceptable because the inconsistency between references has been clarified. Therefore, the staff's concern described in RAI 2.4.6
| |
| -2 is resolved.
| |
| 2.4.6.3 Conclusion The staff reviewed the LRA, UFSAR, and RAI response, to determine whether the applicant had identified all SCs within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all SCs subject to an AMR. On the basis of its review, the staff concludes that the applicant has adequately identified the supports SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| | |
| ====2.4.7 Turbine====
| |
| Building 2.4.7.1 Summary of Technical Information in the Application In LRA Section 2.4.7, the applicant described the turbine building as a non
| |
| -seismic Category I structure that houses the turbine generator and the associated condensers, pumps, and feedwater heaters. In addition, the structure also houses the lube oil, secondary component cooling, and service and instrument air systems. The structure does not support any safety
| |
| -related function per 10 CFR 54.4(a)(1). The structure only supports 10 CFR 54.4(a)(2) and 10 CFR 54.4(a)(3) functions.
| |
| LRA Table 2.4-7 identifies the components, subject to an AMR for the turbine building SCs within license renewal, by component type and intended function.
| |
| 2.4.7.2 Conclusion The staff reviewed the LRA and UFSAR to determine whether the applicant had identified all SCs within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all SCs subject to an AMR. On the basis of its review, the staff concludes that the applicant has adequately identified the turbine building SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| | |
| ====2.4.8 Water====
| |
| Control Structures 2.4.8.1 Summary of Technical Information in the Application In LRA Section 2.4.8, the applicant described the water control structures as those structures used for cooling water for the ultimate heat sink. They consist of the structures described below. Service Water Cooling Tower. The service water cooling tower is categorized as a seismic Category I structure, and it is composed of a concrete basin, pump rooms, electrical switchgear rooms, and mechanical equipment rooms.
| |
| Service Water Pumphouse. The service water pumphouse is categorized as a seismic Category I structure, and it contains the four service water pumps, which are available for Structures and Components Subject to Aging Management Review 2-129 normal operation and for post
| |
| -accident cooldown. The structure is physically adjacent to the circulating water pumphouse.
| |
| Circulating Water Pumphouse. The circulating water pumphouse is categorized as a seismic Category I structure composed of a forebay and three bays with a circulating pump in each bay. Each pump bay has one traveling screen. The three pumps located in each bay supply cooling water to the condensers.
| |
| LRA Table 2.4
| |
| -8 identifies the components, subject to an AMR for the water control structures SCs within license renewal, by component type and intended function.
| |
| 2.4.8.2 Conclusion The staff reviewed the LRA and UFSAR to determine whether the applicant had identified all SCs within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all SCs subject to an AMR. On the basis of its review, the staff concludes that the applicant has adequately identified the water control structures SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| | |
| ===2.5 Scoping===
| |
| and Screening Results: Electrical and Instrumentation and Control Systems This section documents the staff's review of the applicant's scoping and screening results for electrical and I&C systems.
| |
| In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, lo ng-lived SCs within the scope of license renewal and subject to an AMR. To verify that the applicant properly implemented its methodology, the staff's review focused on the implementation results. This focus allowed the staff to confirm that there were no omissions of electrical and I&C system components that meet the scoping criteria and are subject to an AMR. The staff's evaluation of the information in the LRA was the same for all electrical and I&C systems. The objective was to determine if the applicant has identified, in accordance with 10 CFR 54.4, components and supporting structures for electrical and I&C systems that appear to meet the license renewal scoping criteria. Similarly, the staff evaluated the applicant's screening results to verify that all passive, long
| |
| -lived components were subject to an AMR, in accordance with 10 CFR 54.21(a)(1).
| |
| In its scoping evaluation, the staff reviewed the applicable LRA sections, focusing on components that have not been identified as within the scope of license renewal. The staff reviewed relevant licensing basis documents, including the UFSAR, for each electrical and I&C system to determine if the applicant omitted from the scope of license renewal components with intended functions delineated under 10 CFR 54.4(a). The staff also reviewed the licensing basis documents to determine if the LRA specified all intended functions delineated under 10 CFR 54.4(a). The staff requested additional information to resolve any omissions or discrepancies identified.
| |
| | |
| Structures and Components Subject to Aging Management Review 2-130 After its review of the scoping results, the staff evaluated the applicant's screening results. For those SCs with intended functions, the staff sought to determine if the functions are performed with moving parts or a change in configuration or properties or if the SCs are subject to replacement after a qualified life or specified time period, as described in 10 CFR 54.21(a)(1). For those meeting neither of these criteria, the staff sought to confirm that these SCs were subject to an AMR, as required by 10 CFR 54.21(a)(1). The staff requested additional information to resolve any omissions or discrepancies identified.
| |
| | |
| ====2.5.1 Electrical====
| |
| Component Groups 2.5.1.1 Summary of Technical Information in the Application LRA Section 2.5 describes the electrical and I&C systems. The scoping method considers all electrical and I&C systems, including components in the recovery path for loss of offsite power in the event of an SBO. The plant
| |
| -wide approach for the review of plant equipment eliminates the need to indicate each unique component and its specific location and precludes improper exclusion of components from an AMR.
| |
| This approach groups all electrical and I&C components in commodity groups and identifies those electrical commodity groups that are subject to an AMR by applying the criteria of 10 CFR 54.21(a)(1). Electrical components in the SBO recovery path are identified based on their intended function. Components interfacing with the electrical and I&C components are assessed in the appropriate mechanical or structural sections. LRA Table 2.5.4
| |
| -1 identifies the following component and commodity types and their intended functions within the scope of license renewal and subject to an AMR:
| |
| * non-EQ electrical cables and connections
| |
| -electrical continuity
| |
| * metal enclosed bus
| |
| -electrical continuity, insulation
| |
| -electrical
| |
| * fuse holders (not part of a larger assembly) metallic clamp
| |
| -electrical continuity
| |
| * cable connections (metallic parts)
| |
| -electrical continuity
| |
| * SF 6 insulated bus, connections and insulators
| |
| -electrical continuity, insulation
| |
| -electrical 2.5.1.2 Staff Evaluation The staff reviewed LRA Section 2.5 and UFSAR Sections 7 and 8 using the evaluation methodology described in SER Section 2.5 and the guidance in SRP-LR Section 2.5, "Scoping and Screening Results: Electrical and Instrumentation and Controls Systems."
| |
| During its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant has not omitted, from the scope of license renewal, any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as within the scope of license renewal to verify that the applicant has not omitted any passive and long
| |
| -lived components subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).
| |
| GDC 17 of 10 CFR Part 50, Appendix A, requires that electric power from the transmission network to the onsite electric distribution system is supplied by two physically independent circuits to minimize the likelihood of their simultaneous failure. In addition, the staff noted the guidance provided by letter dated April 1, 2002 (ADAMS Accession No. ML020920464), "Staff Structures and Components Subject to Aging Management Review 2-131 Guidance on Scoping of Equipment Relied on To Meet the Requirements of the Station Blackout Rule (10 CFR 50.63) for License Renewal (10 CFR 54.4(a)(3))," and later incorporated in SRP
| |
| -LR Section 2.5.2.1.1.
| |
| For purposes of the license renewal rule, the staff determined that the plant system portion of the offsite power system, which is used to connect the plant to the offsite power source, should be included within the scope of the rule. This path typically includes switchyard circuit breakers that connect to the offsite system power transformers (startup transformers), the transformers themselves, the intervening overhead or underground circuits between circuit breaker and transformer and transformer and onsite electrical system, and the associated control circuits and structures. Ensuring that the appropriate offsite power system long
| |
| -lived passive SSCs that are part of this circuit path are subject to an AMR will ensure that the bases underlying the SBO requirements are maintained over the period of extended license.
| |
| The applicant included the complete circuits between the onsite circuits and up to and including the switchyard 345 kV power circuit breakers connecting to the generator step up (GSU) transformer, the unit auxiliary transformers (UATs), and the reserve auxiliary transformers (RATs) that are within the scope of license renewal. The circuit from the 345 kV power circuit breakers
| |
| -through the UATs to the diesel
| |
| -backed 4,160 volt (V) emergency buses-includes the SF 6 bus from the 345 kV power circuit breakers to the GSU transformer, the isolated phase bus from the GSU to the UATs, and the non
| |
| -segregated bus from the UATs to the 4,160 V Buses E5 (EDE
| |
| -SWG-5) and E6 (EDE
| |
| -SWG-6). The circuit from the 345 kV power circuit breakers
| |
| -through the RAT to the diesel
| |
| -backed 4,160 V emergency buses
| |
| -includes the SF 6 bus from the 345 kV power circuit breakers to the RATs and the non
| |
| -segregated bus from the RATs to the 4,160 V Buses E5 (EDE
| |
| -SWG-5) and E6 (EDE
| |
| -SWG-6). Consequently, the staff concludes that the scoping is consistent with the guidance issued April 1, 2002, and later incorporated in SRP
| |
| -LR Section 2.5.2.1.1.
| |
| The applicant did not include cable tie wraps in the commodity groups subject to an AMR because, based on a review, the applicant concluded that cable tie wraps would not prevent in-scope electrical conductors from performing their intended function. The staff reviewed the UFSAR and found that cable tie wraps are not credited in Seabrook's design basis. Therefore, the staff concludes that the exclusion of cable tie wraps from the commodity groups subject to an AMR is acceptable.
| |
| 2.5.1.3 Conclusion The staff reviewed the LRA and UFSAR to determine whether the applicant had identified all SCs within the scope of license renewal. In addition, the staff's review determined whether the applicant had identified all SCs subject to an AMR. On the basis of its review, the staff concludes that the applicant has adequately identified the electrical and I&C systems components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| | |
| ===2.6 Conclusion===
| |
| for Scoping and Screening The staff reviewed the information in LRA Section 2, "Scoping and Screening Methodology for Identifying Structures and Components Subject to Aging Management Review, and Implementation Results." The staff finds that the applicant's scoping and screening Structures and Components Subject to Aging Management Review 2-132 methodology is consistent with the requirements of 10 CFR 54.4(a) for identifying SSCs within the scope of license renewal and 10 CFR 54.21(a)(1) for identifying SCs subject to an AMR.
| |
| On the basis of its review, the staff concluded that the applicant adequately identified those SSCs that are within the scope of license renewal, as required by 10 CFR 54.4(a), and those SCs that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
| |
| | |
| 3-1 SECTION 3 AGING MANAGEMENT REVIEW RESULTS This section of the safety evaluation report (SER) evaluates aging management programs (AMPs) and aging management reviews (AMRs) for Seabrook Station, Unit No. 1 (Seabrook). The evaluation is performed by the staff of the U.S. Nuclear Regulatory Commission (NRC) (the staff). In Appendix B to its license renewal application (LRA), NextEra Energy Seabrook, LLC (NextEra, the applicant) described the 42 AMPs that it relies on to manage or monitor the aging of passive, long
| |
| -lived structures and components (SCs). In LRA Section 3, the applicant provided the results of the AMRs for those SCs identified in LRA Section 2 as within the scope of license renewal and subject to an AMR.
| |
| | |
| ===3.0 Applicant's===
| |
| Use of the Generic Aging Lessons Learned Report In preparing its LRA, the applicant credited NUREG
| |
| -1801, Revision 1, "Generic Aging Lessons Learned (GALL) Report," dated September 2005. The GALL Report contains the staff's generic evaluation of the existing plant programs and documents the technical basis for determining where existing programs are adequate without modification and where existing programs should be augmented for the period of extended operation. The evaluation results documented in the GALL Report indicate that many of the existing programs are adequate to manage the aging effects for particular license renewal SCs. The GALL Report also contains recommendations on specific areas for which existing programs should be augmented for license renewal. An applicant may reference the GALL Report in its LRA to demonstrate that its programs correspond to those reviewed and approved in the report.
| |
| The purpose of the GALL Report is to provide a summary of staff
| |
| -approved AMPs to manage or monitor the aging of SCs subject to an AMR. If an applicant commits to implementing these staff-approved AMPs, the time, effort, and resources for LRA review will be greatly reduced, improving the efficiency and effectiveness of the license renewal review process. The GALL Report also serves as a quick reference for applicants and staff reviewers to AMPs and activities that the staff has determined will adequately manage or monitor aging during the period of extended operation.
| |
| The GALL Report identifies the following:
| |
| * systems, structures, and components (SSCs)
| |
| * SC materials
| |
| * environments to which the SCs are exposed
| |
| * aging effects of the materials and environments
| |
| * AMPs credited with managing or monitoring the aging effects
| |
| * recommendations for further applicant evaluations of aging management for certain component types To determine whether the use of the GALL Report would improve the efficiency of LRA review, the staff conducted a demonstration of the GALL Report process in order to model the Aging Management Review Results 3-2 format and content of safety evaluations based on it. The results of the demonstration project confirmed that the GALL Report process will improve the efficiency and effectiveness of LRA review while maintaining the staff's focus on public health and safety. NUREG
| |
| -1800, Revision 1, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants" (SRP
| |
| -LR), dated September 2005, was prepared based on both the GALL Report model and lessons learned from the demonstration project.
| |
| The staff's review complied with Title 10 of the Code of Federal Regulations
| |
| , Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants," (10 CFR Part 54) and the guidance of the SRP
| |
| -LR and the GALL Report.
| |
| In addition to its review of the LRA, the staff conducted onsite audits of selected AMPs to verify the applicant's claims of consistency with the GALL Report during the weeks of October 11, 2010, and October 18, 2010, as described in the "Audit Report Regarding the Seabrook Station License Renewal Application," dated March 21, 2011 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML110280424). The onsite audits and reviews are designed to maximize efficiency of the staff's LRA review because the applicant can respond to questions, the staff can readily evaluate the applicant's responses, and the need for formal correspondence between the staff and the applicant is reduced. 3.0.1 Format of the License Renewal Application The applicant submitted an application that follows the standard LRA format agreed to by the staff and the Nuclear Energy Institute (NEI) by letter dated April 7, 2003 (ADAMS Accession No. ML030990052). This revised LRA format incorporates lessons learned from the staff's reviews of the previous LRAs, which used a format developed from information gained during a staff-NEI demonstration project conducted to evaluate the use of the GALL Report in the LRA review process.
| |
| The organization of LRA Chapter 3 parallels that of SRP
| |
| -LR Chapter 3. LRA Chapter 3 presents AMR results information in the following table types:
| |
| * Table 3.x.1 (Table 1's)
| |
| -In these tables, "3" indicates the LRA section number, "x" indicates the subsection number from the GALL Report, and "1" indicates that this table type is the first in LRA Section 3.
| |
| Table 3.x.2
| |
| -y (Table 2's)
| |
| -In these tables, "3" indicates the LRA section number, "x" indicates the subsection number from the GALL Report, "2" indicates that this table type is the second in LRA Section 3, and "y" indicates the system table number.
| |
| The content of the GALL Report tables and the LRA tables are essentially the same. In its LRA, the applicant modified the tables in Chapter 3 to provide additional information that would assist the staff in its review. In each Table 1, the applicant summarized the portions of the application with respect to consistency with the GALL Report. In each Table 2, the applicant identified the linkage between the scoping and screening results in Chapter 2 and the AMRs in Chapter 3.
| |
| 3.0.1.1 Overview of Table 1's Each of the Tables 3.x.1 (Table 1's) provides a summary comparison of how the facility aligns with the corresponding tables of the GALL Report. These tables are essentially the same as Tables 1-6 provided in the GALL Report, Volume 1, except that the "ID" column has been
| |
| | |
| Aging Management Review Results 3-3 replaced by an "Item Number" column, the "Type" column is removed, and the "Related Generic Item" and "Unique Item" columns have been replaced by a "Discussion" column. The "Discussion" column is used by the applicant to provide clarifying and amplifying information. The following are examples of information that the applicant placed within this column:
| |
| * further evaluation recommended
| |
| -information or reference to where that information is located
| |
| * the name of a plant
| |
| -specific program
| |
| * exceptions to GALL Report assumptions
| |
| * discussion of how the item is consistent with the corresponding item in the GALL Report when the consistency may not be obvious
| |
| * discussion of how the item is different from the corresponding item in the GALL Report (e.g., when an exception is taken to a GALL Report AMP)
| |
| The format of the Table 1's allows the staff to align a specific Table 1 row with the corresponding GALL Report table row so that the consistency can be easily checked.
| |
| 3.0.1.2 Overview of Table 2's Each of the Tables 3.x.2
| |
| -y (Table 2's) provides the detailed results of the AMRs for those components identified in LRA Chapter 2 as subject to an AMR. The LRA contains a Table 2 for each of the systems or components "y" within a system grouping "x" (e.g., reactor coolant systems (RCSs), ESFs, auxiliary systems). For example, the ESFs group (3.2.2
| |
| -y) contains tables specific to the containment vessel spray system, safety injection (SI) system, and residual heat removal (RH) system. Each Table 2 consists of the following columns:
| |
| * Component Type
| |
| -The first column identifies the component types, commodity groups, structural members, or subcomponents from LRA Chapter 2 that are subject to an AMR. The component types are listed in alphabetical order.
| |
| * Intended Function
| |
| -The second column contains the license renewal intended functions for the listed component types. Definitions of intended functions are contained in LRA Table 2.0-1.
| |
| * Material-The third column lists the particular materials of construction for the component type.
| |
| * Environment
| |
| -The fourth column lists the environment to which the component types are exposed. Internal and external service environments are indicated, and a list of these environments is provided in LRA Table 3.0
| |
| -1.
| |
| * Aging Effect Requiring Management (AERM)
| |
| -The fifth column lists aging effects and AERMs. As part of the AMR process, the applicant determined any AERMs for each combination of material and environment.
| |
| * AMPs-The sixth column lists the AMPs that the applicant used to manage the identified aging effects.
| |
| * GALL Report Volume 2 Line Item-The seventh column lists the GALL Report item(s) that the applicant identified as corresponding to the AMR results in the LRA. The Aging Management Review Results 3-4 applicant compared each combination of component type, material, environment, AERM, and AMP in LRA Table 2 to the items in the GALL Report. If there were no corresponding items in the GALL Report, the applicant indicated "None" in the column. In this way, the applicant identified the AMR results in the LRA tables that corresponded to the items in the GALL Report tables.
| |
| * Table 1 Item
| |
| -The eighth column lists the corresponding summary item number from Table 1. If the applicant identified AMR results in Table 2 that are consistent with the GALL Report, then the associated Table 3.x.1 line summary item number should be listed in Table 2. If there is no corresponding item in the GALL Report, then the eighth column indicates "None." That way, the information from the two tables can be correlated.
| |
| * Notes-The ninth column lists the corresponding notes that the applicant used to identify how the information in Table 2 aligns with the information in the GALL Report. The notes identified by letters were developed by an NEI working group to be used in LRAs. Any plant-specific notes are identified by a number and provide additional information concerning the consistency of the item with the GALL Report or other clarifying information.
| |
| | |
| ====3.0.2 Staff's====
| |
| Review Process The staff conducted the following types of evaluations of the AMRs and AMPs:
| |
| * For items that the applicant stated were consistent with the GALL Report, the staff conducted either an audit or a technical review to determine consistency.
| |
| * For items that the applicant stated were consistent with the GALL Report with exceptions, enhancements, or both, the staff conducted either an audit or a technical review of the item to determine consistency. In addition, the staff conducted either an audit or a technical review of the applicant's technical justifications for the exceptions or the adequacy of the enhancements.
| |
| The SRP-LR states that an applicant may take one or more exceptions to specific GALL Report AMP elements; however, any deviation from or exception to the GALL Report AMP should be described and justified. Therefore, the staff considers exceptions as being portions of the GALL Report AMP that the applicant does not intend to implement.
| |
| In some cases, an applicant may choose an existing plant program that does not meet all the program elements defined in the GALL Report AMP. However, the applicant may make a commitment to augment the existing program to satisfy the GALL Report AMP prior to the period of extended operation. Therefore, the staff considers these augmentations or additions to be enhancements. Enhancements include, but are not limited to, activities needed to ensure consistency with the GALL Report recommendations. Enhancements may expand, but not reduce, the scope of an AMP.
| |
| * For other items, the staff conducted a technical review to verify conformance with 10 CFR 54.21(a)(3) requirements.
| |
| | |
| Aging Management Review Results 3-5 Staff audits and technical reviews of the applicant's AMPs and AMRs determine if the aging effects on SCs can be adequately managed to maintain their intended function(s) consistent with the plant's current licensing basis (CLB) for the period of extended operation, as required by 10 CFR Part 54.
| |
| 3.0.2.1 Review of Aging Management Programs For AMPs for which the applicant claimed consistency with the GALL Report AMPs, the staff conducted either an audit or a technical review to verify the claim. For each AMP with one or more deviations, the staff evaluated each deviation to determine if the deviation was acceptable and if the modified AMP would adequately manage the aging effect(s) for which it was credited. For AMPs not evaluated in the GALL Report, the staff performed a full review to determine their adequacy. The staff evaluated the AMPs against the following ten program elements defined in SRP-LR, Appendix A:
| |
| * Scope of the Program
| |
| -Scope of the program should include the specific SCs subject to an AMR for license renewal.
| |
| * Preventive Actions
| |
| -Preventive actions should prevent or mitigate aging degradation.
| |
| * Parameters Monitored or Inspected
| |
| -Parameters monitored or inspected should be linked to the degradation of the particular SC's intended function(s).
| |
| * Detection of Aging Effects
| |
| -Detection of aging effects should occur before there is a loss of SC's intended function(s). This includes aspects such as method or technique (i.e., visual, volumetric, surface inspection), frequency, sample size, data collection, and timing of new and one
| |
| -time inspections to ensure timely detection of aging effects.
| |
| * Monitoring and Trending
| |
| -Monitoring and trending should provide predictability of the extent of degradation as well as timely corrective or mitigative actions.
| |
| * Acceptance Criteria
| |
| -Acceptance criteria, against which the need for corrective action will be evaluated, should ensure that the SC's intended function(s) are maintained under all CLB design conditions during the period of extended operation.
| |
| * Corrective Actions
| |
| -Corrective actions, including root cause determination and prevention of recurrence, should be timely.
| |
| * Confirmation Process
| |
| -Confirmation process should ensure that preventive actions are adequate and that appropriate corrective actions have been completed and are effective.
| |
| * Administrative Controls
| |
| -Administrative controls should provide for a formal review and approval process.
| |
| * Operating Experience
| |
| -Operating experience of the AMP, including past corrective actions resulting in program enhancements or additional programs, should provide objective evidence to support the conclusion that the effects of aging will be adequately managed so that the SC's intended function(s) will be maintained during the period of extended operation.
| |
| Details of the staff's audit evaluation of program elements one through six and ten are documented in the AMP audit report and are summarized in SER Section 3.0.3.
| |
| | |
| Aging Management Review Results 3-6 The staff reviewed the applicant's quality assurance (QA) Program and documented its evaluations in SER Section 3.0.4. The staff's evaluation of the QA Program included assessment of the "corrective actions," "confirmation process," and "administrative controls" program elements, which are program elements 7, 8, and 9.
| |
| The staff reviewed the information on the "operating experience" program element and documented its evaluation in SER Section 3.0.5.
| |
| 3.0.2.2 Review of Aging Management Review Results Each LRA Table 2 contains information concerning whether the AMRs identified by the applicant align with the GALL Report AMRs. For a given AMR in a Table 2, the staff reviewed the intended function, material, environment, AERM, and AMP combination for a particular system component type. Item numbers in the seventh column of the LRA, "NUREG
| |
| -1801 Vol. 2 Item," correlate to an AMR combination as identified in the GALL Report. The staff also conducted onsite audits to verify these correlations. A "None" in the seventh column indicates that the applicant was unable to identify an appropriate correlation in the GALL Report. The staff also conducted a technical review of combinations not consistent with the GALL Report. The next column, "Table 1 Item," refers to a number indicating the correlating row in Table 1.
| |
| For component groups evaluated in the GALL Report for which the applicant claimed consistency with the report and for which it does not recommend further evaluation, the staff's audit and review determined if the plant
| |
| -specific components of these GALL Report component groups were bounded by the GALL Report evaluation.
| |
| The applicant noted, for each AMR item, how the information in the tables aligns with the information in the GALL Report. The staff audited those AMRs with Notes A
| |
| -E, indicating how the AMR is consistent with the GALL Report.
| |
| Note A indicates that the AMR item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. The staff audited these items to verify consistency with the GALL Report and validity of the AMR for the site
| |
| -specific conditions.
| |
| Note B indicates that the AMR item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP takes some exceptions to the GALL Report AMP. The staff audited these items to verify consistency with the GALL Report and confirmed that the identified exceptions to the GALL Report AMPs have been reviewed and accepted. The staff also determined whether the applicant's AMP was consistent with the GALL Report AMP and whether the AMR was valid for the site
| |
| -specific conditions.
| |
| Note C indicates that the component for the AMR item, although different from the component identified in the GALL Report, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. This note indicates that the applicant was unable to find a listing of some system components in the GALL Report; however, the applicant identified in the GALL Report a different component with the same material, environment, aging effect, and AMP as the component under review. The staff audited these items to verify consistency with the GALL Report. The staff also determined whether the AMR item of the different component was applicable to the component under review and whether the AMR was valid for the site
| |
| -specific conditions.
| |
| | |
| Aging Management Review Results 3-7 Note D indicates that the component for the AMR item, although different from the component identified in the GALL Report, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the GALL Report AMP. The staff audited these items to verify consistency with the GALL Report. The staff confirmed whether the AMR item of the different component was applicable to the component under review and whether the identified exceptions to the GALL Report AMPs have been reviewed and accepted. The staff also determined whether the applicant's AMP was consistent with the GALL Report AMP and whether the AMR was valid for the site
| |
| -specific conditions.
| |
| Note E indicates that the AMR item is consistent with the GALL Report for material, environment, and aging effect, but credits a different AMP. The staff audited these items to verify consistency with the GALL Report. The staff also determined whether the credited AMP would manage the aging effect consistently with the GALL Report AMP and whether the AMR was valid for the site
| |
| -specific conditions.
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| 3.0.2.3 Updated Final Safety Analysis Report Supplement Consistent with the SRP
| |
| -LR for the AMRs and AMPs that it reviewed, the staff also reviewed the updated final safety analysis report (UFSAR) supplement, which summarizes the applicant's programs and activities for managing aging effects for the period of extended operation, as required by 10 CFR 54.21(d).
| |
| 3.0.2.4 Documentation and Documents Reviewed In its review, the staff used the LRA, LRA supplements, the SRP
| |
| -LR, and the GALL Report.
| |
| During the onsite audit, the staff also examined the applicant's justifications to verify that the applicant's activities and programs will adequately manage the effects of aging on SCs. The staff also conducted detailed discussions and interviews with the applicant's license renewal project personnel and others with technical expertise relevant to aging management.
| |
| During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine whether they are bounded by the conditions for which the GALL Report was evaluated.
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| Unless otherwise stated, the staff compared elements one through six of the applicant's program to the corresponding elements of the GALL Report and found that the elements are bounded. For program elements inconsistent with the corresponding element of the GALL Report, the staff determined the need for additional clarification, which resulted in the issuance of a request for additional information (RAI).
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| | |
| ====3.0.3 Aging====
| |
| Management Programs SER Table 3.0
| |
| -1 presents the AMPs credited by the applicant and described in LRA Appendix B. The table also indicates the systems or structures, which credit the AMPs and the GALL Report AMP, with which the applicant claimed consistency and shows the section of this SER in which the staff's evaluation of the program is documented.
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| | |
| Aging Management Review Results 3-8 Table 3.0-1. Aging Management Programs Applicant AMP LRA section(s)
| |
| New or existing AMP GALL Report comparison GALL Report AMPs Staff's SER Section ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program A.2.1.1 B.2.1.1 Existing Consistent XI.M1, "ASME Section XI Inservice Inspection, Subsection IWB, IWC, and IWD" 3.0.3.1.1 Water Chemistry Program A.2.1.2 B.2.1.2 Existing Consistent XI.M2, "Water Chemistry" 3.0.3.1.2 Reactor Head Closure Studs Program A.2.1.3 B.2.1.3 Existing Consistent with exception XI.M3, "Reactor Head Closure Studs" 3.0.3.2.1 Applicant AMP LRA section(s)
| |
| New or existing AMP GALL Report comparison GALL Report AMPs Staff's SER Section Boric Acid Corrosion Program A.2.1.4 B.2.1.4 Existing Consistent XI.M10, "Boric Acid Corrosion" 3.0.3.1.3 Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program A.2.1.5 B.2.1.5 Existing Consistent XI.M11A, "Nickel
| |
| -Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactor" 3.0.3.1.4 Fuse Holders Program A.2.1.36 B.2.1.36 New Consistent XI.E5, "Fuse Holders" 3.0.3.1.5 Flow-Accelerated Corrosion Program A.2.1.8 B.2.1.8 Existing Consistent with enhancement XI.M17, "Flow
| |
| -Accelerated Corrosion" 3.0.3.1.6 Bolting Integrity Program A.2.1.9 B.2.1.9 Existing Consistent XI.M18, "Bolting Integrity" 3.0.3.1.7 Steam Generator Tube Integrity Program A.2.1.10 B.2.1.10 Existing Consistent XI.M19, "Steam Generator Tube Integrity" 3.0.3.2.2 Open-Cycle Cooling Water System Program A.2.1.11 B.2.1.11 Existing Consistent with exception and enhancements XI.M20, "Open
| |
| -Cycle Cooling Water System" 3.0.3.2.3 Closed-Cycle Cooling Water System Program A.2.1.12 B.2.1.12 Existing Consistent with exceptions and enhancements XI.M21, "Closed
| |
| -Cycle Cooling Water System" 3.0.3.2.4 Inspection of Overhead Heavy Load and Light Load Handling Systems Program A.2.1.13 B.2.1.13 Existing Consistent with enhancements XI.M23, "Inspection of Overhead Heavy Load and Light Load Handling Systems" 3.0.3.2.5 Compressed Air Monitoring Program A.2.1.14 B.2.1.14 Existing Consistent with enhancement XI.M24, "Compressed Air Monitoring" 3.0.3.2.6 Fire Protection Program A.2.1.15 B.2.1.15 Existing Consistent with enhancements XI.M26, "Fire Protection" 3.0.3.2.7
| |
| | |
| Aging Management Review Results 3-9 Fire Water System Program A.2.1.16 B.2.1.16 Existing Consistent with enhancements XI.M27, "Fire Water System" 3.0.3.2.8 Aboveground Steel Tanks Program A.2.1.17 B.2.1.17 Existing Consistent with enhancements XI.M29, "Aboveground Steel Tanks" 3.0.3.2.9 Fuel Oil Chemistry Program A.2.1.18 B.2.1.18 Existing Consistent with exceptions and enhancements XI.M30, "Fuel Oil Chemistry" 3.0.3.2.10 Reactor Vessel Surveillance Program A.2.1.19 B.2.1.19 Existing Consistent with enhancements XI.M31, "Reactor Vessel Surveillance" 3.0.3.2.11 One-Time Inspection Program A.2.1.20 B.2.1.20 New Consistent XI.M32, "One
| |
| -Time Inspection" 3.0.3.1.8 Selective Leaching of Materials Program A.2.1.21 B.2.1.21 New Consistent with exception XI.M33, "Selective Leaching of Materials" 3.0.3.2.12 Buried Piping and Tanks Inspection Program A.2.1.22 B.2.1.22 New Plant-specific None 3.0.3.3.1 One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program A.2.1.23 B.2.1.23 New Consistent with exception XI.M35, "One
| |
| -Time Inspection of ASME Code Class 1 Small
| |
| -Bore Piping" 3.0.3.2.13 Applicant AMP LRA section(s)
| |
| New or existing AMP GALL Report comparison GALL Report AMPs Staff's SER Section External Surfaces Monitoring Program A.2.1.24 B.2.1.24 Existing Consistent with exceptions and enhancements XI.M36, "External Surfaces Monitoring" 3.0.3.2.14 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program A.2.1.25 B.2.1.25 New Consistent with exceptions and enhancements XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 3.0.3.2.15 Lubricating Oil Analysis Program A.2.1.26 B.2.1.26 Existing Consistent with exception and enhancements XI.M39, "Lubricating Oil Analysis" 3.0.3.2.16 ASME Code Section XI, Subsection IWE Program A.2.1.27 B.2.1.27 Existing Consistent with enhancements XI.S1, "ASME Section XI, Subsection IWE" 3.0.3.1.9 ASME Code Section XI, Subsection IWL Program A.2.1.28 B.2.1.28 Existing Consistent with enhancements XI.S2, "ASME Section XI, Subsection IWL" 3.0.3.2.17 ASME Code Section XI, Subsection IWF Program A.2.1.29 B.2.1.29 Existing Consistent XI.S3, "ASME Section XI, Subsection IWF" 3.0.3.1.10 10 CFR Part 50, Appendix J Program A.2.1.30 B.2.1.30 Existing Consistent with exceptions XI.S4, "10 CFR Part 50, Appendix J" 3.0.3.1.11
| |
| | |
| Aging Management Review Results 3-10 Structures Monitoring Program A.2.1.31 B.2.1.31 Existing Consistent with enhancements XI.S5, "Masonry Wall" XI.S6," Structures Monitoring" XI.S7, "RG 1.127, Inspection of Water
| |
| -Control Structures Associated with Nuclear Power Plants" 3.0.3.2.18 Electrical Cables and Connections Not Subject to 10 CFR 50.49 environmental qualification (EQ)
| |
| Requirements Program A.2.1.32 B.2.1.32 New Consistent XI.E1, "Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements" 3.0.3.1.12 Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program A.2.1.33 B.2.1.33 New Consistent XI.E2, "Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits" 3.0.3.1.13 Inaccessible Power Cables Not Subject to 10 CFR 50.49 EQ Requirements Program* A.2.1.34 B.2.1.34 New Consistent with enhancement XI.E3, "Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements" 3.0.3.2.19 Metal Enclosed Bus (MEB) Program A.2.1.35 B.2.1.35 New Consistent XI.E4, "Metal Enclosed Bus" 3.0.3.1.14 Applicant AMP LRA section(s)
| |
| New or existing AMP GALL Report comparison GALL Report AMPs Staff's SER Section Electrical Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements Program A.2.1.37 B.2.1.37 New Consistent XI.E6, "Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements" 3.0.3.1.15 Protective Coating Monitoring and Maintenance Program A.2.1.38 B.2.1.38 Existing Consistent with enhancements XI.S8, "Protective Coating Monitoring and Maintenance" 3.0.3.2.20 345 kV sulfur hexafluoride (SF
| |
| : 6) Bus Program A.2.2.1 B.2.2.1 New Plant-specific None 3.0.3.3.2 Boral Monitoring Program A.2.2.2 B.2.2.2 Existing Plant-specific None 3.0.3.3.3 Nickel-Alloy Nozzles and Penetrations Program A.2.2.3 B.2.2.3 Existing Plant-specific None 3.0.3.3.4 Metal Fatigue of Reactor Coolant Pressure Boundary (RCPB) Program A.2.3.1 B.2.3.1 Existing Consistent with enhancements X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary" 3.0.3.2.21
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| | |
| Aging Management Review Results 3-11 Pressurized
| |
| -Water Reactor (PWR) Vessel Internals Program (VIP)** A.2.1.7 B.2.1.7 New Consistent GALL Report (Rev. 2) AMP XI.M16A, "PWR Vessel Internals" 3.0.3.3.5 EQ of Electric Equipment Program A.2.3.2 B.2.3.2 Existing Consistent X.E1, "Environmental Qualification (EQ) of Electric Components" 3.0.3.1.16 Alkali-Silica Reaction (ASR) Monitoring Program A.2.1.31A B.2.1.31A New Plant-specific None 3.0.3.3.6.
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| Building Deformation Monitoring Program A.2.1.31B B.2.1.31B New Plant-specific None 3.0.3.3.7
| |
| (*) The applicant amended the application to change "Medium
| |
| -Voltage" to "Power" to be consistent with GALL Report Rev. 2. (see SER Appendix A).
| |
| (**) As described in SER Section 3.0.3.3.5, by letter dated May 26, 2015, the applicant amended the LRA with a revised PWR Vessel Internals Program.
| |
| Subsequent to the applicant submitting its LRA, the staff issued several license renewal interim staff guidance (LR
| |
| -ISG) documents. The applicant revised its AMP and AMR items and, in some cases, incorporated new AMR items to address these ISGs. The staff's evaluation of these changes is documented in the SER. Except where the applicant proposed changes t o existing or new AMR items, for the following ISGs, the staff only documented its evaluation of the applicant's proposed changes in the AMP portion of the SER.
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| * LR-ISG-2012-02, "Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation"
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| * LR-ISG-2015-01, "Changes to Buried and Underground Piping and Tank Recommendations" Based on the staff's review of industry operating experience, these ISGs enhanced the recommendations in several GALL Report AMPs. Examples of the enhancements are as follows:
| |
| * AMP XI.M27, "Fire Water System": included many new tests and inspections based on those described in National Fire Protection Association (NFPA)
| |
| -25, "Standard for the Inspection, Testing, and Maintenance of Water
| |
| -Based Fire Protection Systems," and augmented inspections or tests of portions of water
| |
| -based fire protection system components that have been wetted but are normally dry and that cannot be drained or piping segments that allow water to collect.
| |
| * AMP XI.M29, "Aboveground Metallic Tanks": expanded the scope to include indoor large-volume storage tanks (i.e., those with a capacity greater than 100,000 gallons) designed to internal pressures approximating atmospheric pressure and exposed internally to water, included corrosion under insulation as an AERM, and tank internal and external surface inspection recommendations were expanded depending on the type of material, environment, and aging effect.
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| * AMP XI.M36, "External Surfaces Monitoring of Mechanical Components": included corrosion under insulation as an AERM.
| |
| | |
| Aging Management Review Results 3-12
| |
| * AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components": revised the program from inspections being opportunistic to recommending a minimum sample of inspections for each material, environment, and aging effect combination.
| |
| * AMP XI.M41, "Buried and Underground Piping and Tanks": expanded the preventive action recommendations to include cathodic protection and backfill quality in addition to coatings and based inspection quantities on the performance of the cathodic protection system, coatings, backfill quality, plant
| |
| -specific operating experience, and soil testing.
| |
| The basis for not revising the existing AMR item SER input is that: (a) the staff's basis for accepting the AMP proposed by the applicant to manage aging effects associated with the material and environment combination would have been strengthened by the changes in the AMP recommendations, and (b) the staff's evaluation of changes to each AMP is documented in the SER input for the AMP.
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| 3.0.3.1 Aging Management Programs Consistent with the Generic Aging Lessons Learned Report In LRA Appendix B, the applicant identified the following AMPs as consistent with the GALL Report:
| |
| * American Society of Mechanical Engineers (ASME) Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program
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| * Water Chemistry Program
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| * Boric Acid Corrosion Program
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| * Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program
| |
| * Fuse Holders Program
| |
| * Flow-Accelerated Corrosion Program
| |
| * Bolting Integrity Program
| |
| * One-Time Inspection Program
| |
| * ASME Section XI, Subsection IWE Program
| |
| * ASME Section XI, Subsection IWF Program
| |
| * 10 CFR Part 50, Appendix J Program
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| * Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification (EQ) Requirements Program
| |
| * Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program
| |
| * Metal Enclosed Bus (MEB) Program
| |
| * Electrical Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements Program
| |
| * EQ of Electrical Components Program
| |
| | |
| Aging Management Review Results 3-13 3.0.3.1.1 ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program Summary of Technical Information in the Application. LRA Section B.2.1.1 describes the existing ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program as consistent with GALL Report AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD." The applicant stated that this program manages the aging effects of cracking due to cyclic, thermal, or mechanical loading; stress corrosion; loss of fracture toughness due to thermal embrittlement; and loss of material due to pitting, crevice corrosion, or wear. The applicant also stated that this program manages aging degradation in ASME Code Classes 1, 2, and 3 piping and components within the scope of license renewal. The applicant further stated that the program includes periodic visual inspection, surface or volumetric examination, or both for components identified in ASME Code Section XI, "Rules for Inservice Inspection of Nuclear Power Plant Components," or commitments that require an augmentation of inservice inspection (ISI). The applicant also stated that the program will provide the requirements for ISI, repair, and replacement of all ASME Code Classes 1, 2, and 3 components. The applicant further stated that the program consists of condition monitoring activities that will detect degradation of components prior to the loss of intended function.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.M1. As discussed in the AMP audit report, the staff confirmed that each element of the applicant's program is consistent with the corresponding element of GALL Report AMP XI.M1, with the exception of the "detection of aging effects" program element. For this element, the staff determined the need for additional clarification, which resulted in the issuance of a request for additional information (RAI).
| |
| GALL Report AMP XI.M1 recommends that Class 1 component inspections include ASME Code Section XI examination Categories B
| |
| -F and B-J. During the audit, the staff found that the applicant is currently including applicable portions of the Categories B
| |
| -F and B-J in its Risk Informed Inservice Inspection Program. The staff noted that the approval of the risk
| |
| -informed methodology cannot be assumed for the subsequent 10
| |
| -year ISI intervals because the staff's approval of an alternative program or relief request typically does not extend beyond the current 10-year interval for which the alternative was proposed. An applicant must submit relief requests in accordance with 10 CFR 50.55a(a)(3) for use in subsequent 10
| |
| -year ISI intervals during the period of extended operation. By letter dated December 14, 2010 (ADAMS Accession No. ML103260554), the staff issued RAI B.2.1.1
| |
| -1, requesting that the applicant clarify how the inspection of Categories B
| |
| -F and B-J will be implemented during the period o f extended operation.
| |
| In its response dated January 13, 2011 (ADAMS Accession No. ML110140809), the applicant stated that this program has been revised to state that Risk Informed ISI is implemented as an alternative to Categories B
| |
| -F and B-J, as approved by the NRC, for each individual ISI interval. The applicant also stated that if the Risk Informed ISI Program is not approved during the Aging Management Review Results 3-14 period of extended operation, it will follow the applicable requirements of ASME Code Section XI, Subsection IWB.
| |
| Based on its review, the staff finds the applicant's response to RAI B.2.1.1
| |
| -1 acceptable because the applicant modified its ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program. This modification indicated that, if the Risk Informed ISI is not approved for any of the inspection intervals during the period of extended operation, the applicant will instead use the requirements in the ASME Code Section XI, consistent with the recommendations of GALL Report AMP XI.M1. The staff's concern described in RAI B.2.1.1
| |
| -1 is resolved.
| |
| Based on its audit and review of the applicant's response to RAI B.2.1.1
| |
| -1, the staff finds that elements one through six of the applicant's ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program are consistent with the corresponding program elements of GALL Report AMP XI.M1 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.1 summarizes operating experience related to the ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program. In March 2008, the applicant stated that, during a routine visual inspection, excessive dry boric acid accumulation on a containment building spray system valve gland leak
| |
| -off plug was identified. The applicant stated that the gland leak
| |
| -off plug was tightened, and the leakage was stopped. The applicant further stated that, in September 2006, while performing a VT
| |
| -2 visual examination, the inspector identified a packing leak from a main steam valve with the emergency feedwater steam supply header pressurized to the main steam header pressure. The applicant stated that it adjusted the packing to stop the leak. The applicant stated that these examples demonstrate that the VT
| |
| -2 inspections have been effective in identifying degraded conditions.
| |
| The staff reviewed operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the AMP audit report, the staff also conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program. During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that the operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.1 provides the UFSAR supplement for the ASM E Code Section XI ISI, Subsections IWB, IWC, and IWD Program. The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Table 3.1
| |
| -2. The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. Based on its review of the applicant's ASME Code Section XI ISI, Aging Management Review Results 3-15 Subsections IWB, IWC, and IWD Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.1.2 Water Chemistry Program Summary of Technical Information in the Application. LRA Section B.2.1.2 describes the existing Water Chemistry Program as consistent with GALL Report AMP XI.M2, "Water Chemistry." The applicant stated that its Water Chemistry Program manages aging effects of cracking, loss of material, and reduction of heat transfer. The applicant further stated that the primary scope of the program is the RCS and related auxiliary systems. The applicant also stated that the program is used to control water chemistry for impurities. The applicant stated that the chemistry parameters include chlorides, fluorides, dissolved oxygen, and sulfate concentrations. The applicant stated that it bases its monitoring and control on industry guidelines such as Electrical Power Research Institute's (EPRI) "Pressurized Water Reactor Primary Water Chemistry Guidelines
| |
| -Revision 6," for primary water chemistry and "Pressurized Water Reactor Secondary Water Chemistry Guidelines
| |
| -Revision 7," for secondary water chemistry.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.M2. As discussed in the AMP audit report, the staff confirmed that each element of the applicant's program is consistent with the corresponding element of GALL Report AMP XI.M2, with the exception of the "monitoring and trending" program element. For this element, the staff determined the need for additional clarification, which resulted in the issuance of an RAI.
| |
| GALL Report AMP XI.M2 states that whenever corrective actions are taken to address an abnormal chemistry condition, increased sampling is used to verify the effectiveness of these actions. However, during its audit, the staff reviewed the applicant's chemistry guidelines and could not identify any statements that indicated, under abnormal chemistry conditions, the sampling frequency should be increased. By letter dated November 18, 2010 (ADAMS Accession No. ML103090558), the staff issued RAI B.2.1.2
| |
| -1, requesting that the applicant describe how the Water Chemistry Program will verify the effectiveness of corrective actions when an abnormal chemistry conditions occurs.
| |
| In its responses dated December 17, 2010 (ADAMS Accession No. ML103540534) and February 18, 2011 (ADAMS Accession No. ML110530481), the applicant committed (Commitment 62) to revise the chemistry program documents to include the statement that sampling frequencies are increased, as appropriate, when chemistry action levels are exceeded. The staff finds the applicant's response acceptable because it committed to including increased sampling frequencies when chemistry action levels are exceeded, which is consistent with GALL Report AMP XI.M2. The staff's concern described in RAI B.2.1.2
| |
| -1 is resolved.
| |
| Aging Management Review Results 3-16 Based on its audit and review of the applicant's response to RAI B.2.1.2
| |
| -1, the staff finds that elements one through six of the applicant's Water Chemistry Program are consistent with the corresponding program elements of GALL Report AMP XI.M2 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.2 summarizes operating experience related to the Water Chemistry Program. The applicant stated that, in December 2001, the condensate storage tank (CST) oxygen levels increased above 75 parts per billion (ppb). The applicant stated that it took corrective actions by monitoring oxygen concentrations at various points in the condensate and demineralized water system. The applicant stated that the oxygen ingress was caused by the air in
| |
| -leakage from the condensate storage pump. The applicant further stated it repaired the pump, and the CST returned to within the Water Chemistry Program specifications. The applicant also indicated that, in the fall of 2003, the steam generator sludge analysis results indicated that low or less than detectable concentration of contaminants and sulfur were detected by bulk deposit analysis. The applicant stated that this was an example of the effectiveness of the secondary chemistry control program.
| |
| The staff reviewed operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the AMP audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program. During its review, the staff identified operating experience that could indicate that the applicant's program may not be effective in adequately managing aging effects during the period of extended operation. The staff determined the need for additional clarification, which resulted in the issuance of an RAI.
| |
| In LRA Section B.2.1.2, the applicant stated that it addressed operating experience related to water chemistry. However, the staff found that the applicant had a recurring condition with the CST where the specific conductivity is high and out of specification. By letter dated November 18, 2010 (ADAMS Accession No. ML103090558), the staff issued RAI B.2.1.2
| |
| -2, requesting that the applicant provide additional information to explain if the CST conductivity excursions were evaluated for similar root causes.
| |
| If the root cause is the same for the occurrences, the applicant was asked to provide additional information on what steps have been taken to reduce the occurrence of any future CST conductivity excursions.
| |
| In its response dated December 17, 2010 (ADAMS Accession No. ML103540534), the applicant stated that the high specific conductivity in the CST could have been due to either recirculation flows from the startup feed pump and emergency feedwater pumps or air ingress past the CST floating lid seal. The applicant stated that, when the high specific conductivity started, it immediately sampled the CST to determine if any leakage from the auxiliary steam side into the CST had occurred; however, no leakage was found. The applicant stated that the tank was then fed and bled to reduce the high specific conductivity to within acceptable limits. The applicant further stated that, during the April 2008 refueling outage (RFO), it replaced the faulty floating lid seal, and since this time, the specific conductivity has remained below the 0.1 micro siemens (µS) limit. An additional step for conductivity control has been the continued monitoring and replacement of the CST float seal when necessary and the supply of condenser hotwell makeup from the demineralized water storage tank instead of the CST. Based on its review, the staff finds the applicant's response to RAI B.2.1.2
| |
| -2 acceptable because the applicant indicated how this program brought the water chemistry excursions back within limits; Aging Management Review Results 3-17 determined that the likely root cause for the events was due to either recirculation flows from the startup feed pump and emergency feedwater pumps or air ingress past the CST floating lid seal that the applicant replaced; and used monitoring, replacement, and alternate condenser water sources to minimize the possibility of conductivity excursions. The staff's concern described in RAI B.2.1.2
| |
| -2 is resolved.
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| Based on its audit and review of the application, and review of the applicant's response to RAI B.2.1.2
| |
| -2, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.2 provides the UFSAR supplement for the Water Chemistry Program. The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Tables 3.1
| |
| -2, 3.2-2, 3.3-2, 3.4-2, and 3.5
| |
| -2. The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. Based on its review of the applicant's Water Chemistry Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.1.3 Boric Acid Corrosion Program Summary of Technical Information in the Application. LRA Section B.2.1.4 describes the existing Boric Acid Corrosion Program as consistent with GALL Report AMP XI.M10, "Boric Acid Corrosion." The applicant stated that its Boric Acid Corrosion Program manages loss of material in mechanical, electrical, and structural components due to leakage from systems containing borated water. The applicant further stated that the program implements the recommendations of NRC Generic Letter (GL) 88
| |
| -05, "Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR Plants." The applicant also stated that the program includes visual inspections and early discovery of borated water leaks such that mechanical, electrical, and structural components that may be contacted by leaking borated water will not be adversely affected or their intended functions impaired. The applicant also stated that the program includes both focused inspections and observations by plant personnel during normal operational activities and during refueling shutdowns to identify boric acid accumulation or leakage.
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| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bo unded by the conditions for which the GALL Report was evaluated.
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| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.M10. As discussed in the AMP audit report, the staff Aging Management Review Results 3-18 confirmed that these elements are consistent with the corresponding elements of GALL Report AMP XI.M10. Based on its audit, the staff finds that elements one through six of the applicant's Boric Acid Corrosion Program are consistent with the corresponding program elements of GALL Report AMP XI.M10 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.4 summarizes operating experience related to the Boric Acid Corrosion Program. The applicant's operating experience provided details on engineering analyses and corrective actions taken in response to detected leakage of boric acid. In one recorded instance of operating experience, the applicant described the detection of boric acid residue on a chemical and volume control system valve during a plant walkdown. The observation led to actions to replace the affected valve packing. In another instance, the applicant described the detection of boric acid residue on an RH system valve. The observation led to actions to replace the affected valve gasket.
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| The applicant provided an account of a self
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| -assessment of its Boric Acid Corrosion Program conducted in 2008. The self
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| -assessment compared the Seabrook Boric Acid Corrosion Program to the current industry guidance document, Westinghouse Commercial Atomic Power (WCAP)-15988-NP, Revision 1, "Generic Guidance for an Effective Boric Acid Inspection Program for Pressurized Water Reactors," which identifies potential enhancements to the Boric Acid Corrosion Programs described in the utility responses to GL 88
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| -05. The applicant stated that, based on the results of the self
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| -assessment, the program was operationally sound and deemed to be in a mode of continuous improvement. The applicant further described the self
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| -assessment as a source of identified areas where the program could benefit by being more prescriptive in addressing some of the objectives in the WCAP document. Condition reports were generated during the course of the self
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| -assessment. None of these condition reports identified programmatic failures, and all were directed towards future Boric Acid Program enhancements.
| |
| The staff reviewed operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant. As discussed in the AMP audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program. During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.4 provides the UFSAR supplement for the Boric Acid Corrosion Program. The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP-LR Tables 3.1
| |
| -2, 3.2-2, 3.3-2, 3.4-2, 3.5-2, and 3.6
| |
| -2. The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| | |
| Aging Management Review Results 3-19 Conclusion. On the basis of its review of the applicant's Boric Acid Corrosion Program, the staff finds that all program elements are consistent with GALL Report AMP XI.M10. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
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| 3.0.3.1.4 Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program Summary of Technical Information in the Application. LRA Section B.2.1.5 describes the existing Nickel
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| -Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program (hereafter Nickel
| |
| -Alloy Head Penetration Program) as consistent with GALL Report AMP XI.M11A, "Nickel
| |
| -Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors." The applicant stated that the program manages the aging effect of cracking due to primary water stress corrosion cracking (PWSCC) in the reactor coolant environment. The applicant also stated that the program includes all nickel
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| -alloy penetration nozzles welded to the upper reactor vessel head. The applicant further stated that cracking was mitigated through the control of water chemistry.
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| The applicant finally stated that inspections are performed in accordance with ASME Code Case N-729-1, "Alternative Examination Requirements for PWR Reactor Vessel Upper Heads With Nozzles Having Pressure
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| -Retaining Partial
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| -Penetration Welds, Section XI, Division 1, Supp 4," as modified in 10 CFR 50.55a(g)(6)(ii)(D), and this code case and regulation meet the AMP criteria of being "established to supersede the requirements of Order EA 009." Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
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| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.M11A. The staff confirmed that these elements are consistent with the corresponding elements of GALL Report AMP XI.M11A. The staff also noted that the applicant's program includes the inspection requirements for reactor vessel head penetration nozzles in accordance with 10 CFR 50.55a(g)(6)(ii)(D). Based on its review, the staff finds that elements one through six of the applicant's Nickel
| |
| -Alloy Head Penetration Program are consistent with the corresponding program elements of GALL Report AMP XI.M11A and the regulation in 10 CFR 50.55a; therefore, the staff finds them acceptable.
| |
| Operating Experience. LRA Section B.2.1.5 summarizes operating experience related to the Nickel-Alloy Head Penetration Program. In this section, the applicant states that it has conducted several inspections of the upper vessel head penetration nozzles and that it has not detected any indication of PWSCC. As evidence of the effectiveness of its AMP, the applicant provides descriptions of inspection findings for refueling outages (RFOs) 8, 9, 10, and 11 (spring 2002, fall 2003, spring 2005, and fall 2006, respectively). In RFO 8, the applicant performed a robotic bare metal exam of the top head. The applicant stated that no evidence of penetration leakage was observed. In RFO 9, boric acid was observed on the upper reactor vessel head flange. This acid was traced to two leaking canopy seal welds. The applicant states that no boric acid corrosion was observed. The leakage was halted through the Aging Management Review Results 3-20 application of a canopy seal clamp assembly. The applicant attributed the leakage to transgranular cracking due to the presence of halogens, probably chlorides. Followup inspections conducted during RFO 10 and RFO 11 did not identify additional canopy seal weld leaks. In RFO 11, inspections were conducted under the first revised NRC Order EA 009. These inspections included a robotic bare metal examination from the top of the head and a robotic ultrasonic and surface examination of the J
| |
| -groove welds and penetration tubes from the bottom of the head. The applicant stated that no unacceptable indications were discovered.
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| The staff reviewed operating experience information
| |
| -which is contained in the application, in the GALL Report, and which has occurred since the publication of the GALL Report
| |
| -to determine if all the applicable aging effects and industry and plant
| |
| -specific operating experience were considered by the applicant and whether the proposed AMP is sufficient to address this operating experience. During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its review of the application, the GALL Report, and recent industry operating experience, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking appropriate preventive actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.5 provides the UFSAR supplement for the Nickel
| |
| -Alloy Head Penetration Program.
| |
| The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Table 3.1-2. The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. Based on its review of the applicant's Nickel
| |
| -Alloy Head Penetration Program, the staff finds that program elements 1
| |
| -6 and 10 are consistent with the GALL Report. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.1.5 Fuse Holders Program Summary of Technical Information in the Application. LRA Section B.2.1.36 describes the new Fuse Holders Program as consistent with GALL Report AMP XI.E5, "Fuse Holders." The applicant stated that the Fuse Holders Program is a new program that will manage the aging effects of thermal fatigue in the form of high resistance due to corrosion or oxidation of in
| |
| -scope metallic clamps of fuse holders. The applicant also stated that the program will perform tests on the in-scope fuse holders (metallic clamps). The applicant further stated that the test will be a proven test such as thermography or contact resistance, which detects thermal fatigue in the Aging Management Review Results 3-21 form of high resistance caused by corrosion or oxidation. The first test will be completed prior to entering the period of extended operation and at least once every 10 years thereafter.
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| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine whether they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.E5. As discussed in the AMP audit report, the staff confirmed that each element of the applicant's program is consistent with the corresponding elements of GALL Report AMP XI.E5, with the exception of the "parameters monitored or inspected" program element. For this element, the staff determined that additional clarification was required.
| |
| GALL Report AMP XI.E5, under the "parameters monitored or inspected" element, states that the monitoring includes thermal fatigue in the form of high resistance caused by ohmic heating, thermal cycling or electrical transients, mechanical fatigue caused by frequent removal or replacement of the fuse or vibration, chemical contamination, corrosion, and oxidation. In the Seabrook AMP basis document LRAP
| |
| -E5 under the same program element, the applicant states that the Seabrook program only includes monitoring for the presence of corrosion and oxidation. The applicant concluded that the aging effects and mechanisms due to thermal fatigue-in the form of high resistance caused by ohmic heating, thermal cycling or electrical transients, mechanical fatigue caused by frequent removal or replacement of the fuse or vibration-identified by GALL are not applicable to the fuse holders at Seabrook. However, the applicant does not provide any justification to substantiate its conclusion. During the LRA onsite audit in the week of October 18, 2010, the staff discussed the applicant's lack of analysis to exclude certain aging effects for fuse holder metallic clamps in the scope of license renewal. In a letter dated November 15, 2010 (ADAMS Accession No. ML103210330), the applicant revised the Fuse Holders Program description to clarify the exclusion of certain aging mechanisms from the AMP. The staff finds the exclusion of certain aging mechanisms acceptable, as documented in SER Section 3.6.2.3.1.
| |
| Based on its audit and review of the applicant's supplement dated November 15, 2010, the sta ff finds that elements one through six of the applicant's Fuse Holders Program are consistent with the corresponding program elements of GALL Report AMP XI.E5 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.36 summarizes operating experience related to the Fuse Holders Program. The applicant's Fuse Holders Program operating experience evaluation states that Seabrook routinely performs infrared thermography tests on numerous pieces of equipment, including electrical connections, as part of the Preventive Maintenance Program. In 2008, during a routine infrared thermography test, a fuse holder was found to be 50°F [degrees Fahrenheit] hotter than similar fuses in the cabinet. The problem was diagnosed as a defective fuse holder. The documentation identified this anomaly as defective equipment and not age related. The applicant also stated that Seabrook has performed thermography or resistance tests on fuses located in the in
| |
| -scope fuse panels. All recent tests were reviewed and found to be satisfactory. The applicant further stated that, in 2009, members of the Seabrook license renewal team performed a walkdown of the in
| |
| -scope Train "B" fuse cabinets. The walkdown assessed the current condition of the in
| |
| -scope fuse panels. The applicant stated that the walkdown results concluded that fuse blocks showed no signs of excessive heating, Aging Management Review Results 3-22 discoloration, corrosion, degradation, or looseness. However, a condition report was written to document the presence of a residue on the fuse cabinet mounting bolts. The evaluation of the anomaly concluded that residue on the bolts had no effect on the fuse holders.
| |
| The staff reviewed operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program. Further, the staff performed a search of regulatory operating experience for the 10
| |
| -year period through March 2010. Databases were searched using various key word searches and then reviewed by the technical auditor staff.
| |
| During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program and has resulted in the applicant taking corrective action. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.36 provides the UFSAR supplement for the Fuse Holders Program. The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP-LR Table 3.6
| |
| -2. The staff also noted that the applicant committed (Commitment 38) to implement the new Fuse Holders Program prior to entering the period of extended operation for managing aging of applicable components.
| |
| The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its review of the applicant's Fuse Holders Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.1.6 Flow-Accelerated Corrosion Program Summary of Technical Information in the Application. LRA Section B.2.1.8 describes the existing Flow
| |
| -Accelerated Corrosion Program as consistent with GALL Report AMP XI.M17, "Flow-Accelerated Corrosion." The applicant stated that this program manages loss of material due to wall thinning on the internal surfaces of carbon or low alloy steel components containing high-energy fluids. The applicant also stated that the program is based on the guidelines of EPRI NSAC-202L-R2, "Recommendations for an Effective Flow
| |
| -Accelerated Corrosion Program," which includes determining susceptible lines, performing baseline and followup Aging Management Review Results 3-23 inspections to confirm predictions, and repairing or replacing components if needed. The applicant further stated that the program monitors the effects of flow
| |
| -accelerated corrosion by measuring wall thickness of the components, and the inspection schedule is developed based on model prediction, inspection results, and operating experience. The applicant amended the program by including activities related to the management of erosion mechanisms, which include identifying susceptible locations based on extent
| |
| -of-condition reviews and trending wall thickness measurements to adjust monitoring frequencies and to determine the need for repairs or replacements.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.M17. As discussed in the audit report, the staff confirmed that each element of the applicant's program is consistent with the corresponding element of GALL Report AMP XI.M17, with the exception of the "parameters monitored or inspected" program element. For this element, the staff determined the need for additional clarification, which resulted in the issuance of an RAI.
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| GALL Report AMP XI.M17 recommends that the program monitors the aging effects of flow
| |
| -accelerated corrosion on the intended function of piping and components by measuring wall thickness. LRA Section B.2.1.8 states that valves, orifices, equipment nozzles, and other like components, which cannot be inspected completely with ultrasonic testing (UT) techniques due to their shape and thickness, are evaluated based on the wear of piping located immediately downstream. By letter dated December 14, 2010 (ADAMS Accession No. ML103260554), the staff issued RAI B.2.1.8
| |
| -1, requesting that the applicant provide additional information regarding inspection of the valves, orifices, equipment nozzles, and other like components that cannot be inspected completely with ultrasonic techniques due to their shape and thickness if significant wear is detected in piping located immediately downstream. The staff also asked the applicant to explain how the followup inspections will be implemented in the Flow-Accelerated Corrosion Program.
| |
| In its response dated January 13, 2011 (ADAMS Accession No. ML110140809), the applicant stated that its Flow
| |
| -Accelerated Corrosion Program is revised to state that if significant wear is detected in piping immediately downstream of a valve, orifice, equipment nozzle or other like component, the component should also be examined. The applicant also stated that these components will be examined by ultrasonic, radiographic, or visual techniques typically used to inspect valves, orifices, and equipment nozzles. The applicant further stated that the followup inspections will be implemented in the Flow
| |
| -Accelerated Corrosion Program, which is consistent with the guidelines delineated in EPRI NSAC
| |
| -202L-R2. The staff finds the applicant's response acceptable because the applicant's Flow
| |
| -Accelerated Corrosion Program will implement the guidance of EPRI NSAC
| |
| -202L-R2 to include inspections of valves, orifices, equipment nozzles, and other like components using ultrasonic, radiographic, or visual techniques if significant wear is detected in the downstream pipe, which makes the applicant's program consistent with GALL Report AMP XI.M17. The staff's concern described in RAI B.2.1.8
| |
| -1 is resolved.
| |
| | |
| Aging Management Review Results 3-24 Enhancement. In its annual update letter dated July 2, 2013, the applicant added an enhancement to the "scope of program," "parameters monitored or inspected," "detection of aging effects," "monitoring or trending," and "corrective actions" program elements to include management of wall thinning caused by mechanisms other than flow
| |
| -accelerated corrosion. The staff notes that the applicant revised LRA Section A.2.1.8 by including this change and stating that the enhancement will be in accordance with LR
| |
| -ISG-2012-01. The staff also notes that the applicant included Commitment 72 as part of its update for completing this enhancement to the program prior to entering the period of extended operation.
| |
| The staff reviewed this enhancement against the corresponding program elements in GALL Report AMP XI.M17, as modified by LR
| |
| -ISG-2012-01. The staff finds the applicant's enhancement acceptable because the changes to the program will provide for managing wa ll thinning due to erosion mechanisms in addition to wall thinning due to flow
| |
| -accelerated corrosion.
| |
| Based on its audit and review of the applicant's response to RAI B.2.1.8
| |
| -1, and review of the annual update letter dated July 2, 2013, the staff finds that elements one through six of the applicant's Flow
| |
| -Accelerated Corrosion Program are consistent with the corresponding program elements of GALL Report AMP XI.M17 as modified by LR
| |
| -ISG-2012-01 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.8 summarizes operating experience related to the Flow-Accelerated Corrosion Program. The applicant stated that following the initial implementation of CHECWORKS in 1991, a significant portion of the high
| |
| -pressure extraction steam piping was found to be degraded during the first flow
| |
| -accelerated corrosion inspections. As a result, the applicant stated it replaced the piping with a chrome
| |
| -moly material that is more resistant to flow
| |
| -accelerated corrosion, and no degradation has been noted in the piping after replacement. The applicant also stated that, during RFO 8 in 2002, it identified one feedwater heater with wall thinning in the area below the extraction steam inlet nozzle and took appropriate corrective actions to repair the heater using a weld overlay. The applicant further stated that the component is being monitored during each RFO, and no additional wall thinning has been observed since the repair.
| |
| The staff reviewed operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program. During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| | |
| Aging Management Review Results 3-25 UFSAR Supplement. LRA Section A.2.1.8, as amended by the annual update letter dated July 2, 2013, provides the UFSAR supplement for the Flow
| |
| -Accelerated Corrosion Program. The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Tables 3.1
| |
| -2, 3.2-2, and 3.4
| |
| -2; and LR-ISG-2012-01, Table 3.0
| |
| -1. The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its review of the applicant's Flow
| |
| -Accelerated Corrosion Program, the staff finds all program elements consistent with the GALL Report. In addition, the staff reviewed the enhancement and confirmed that its implementation through Commitment 72, prior to the period of extended operation, would make the existing AMP consistent with the GALL Report AMP to which it was compared. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.1.7 Bolting Integrity Program Summary of Technical Information in the Application. LRA Section B.2.1.9 describes the existing Bolting Integrity Program as consistent with GALL Report AMP XI.M18, "Bolting Integrity." The applicant stated that the program covers bolting within the scope of license renewal, including safety
| |
| -related bolting, bolting for nuclear steam supply system (NSSS) component supports, bolting for other pressure
| |
| -retaining components (including nonsafety
| |
| -related bolting), and structural bolting. The applicant also stated that the program manages the aging effects of cracking due to stress corrosion cracking, loss of material due to general, crevice, pitting, and galvanic corrosion, microbiologically
| |
| -influenced corrosion, fouling and wear, and loss of preload due to thermal effects, gasket creep, and self
| |
| -loosening associated with bolting. The applicant further stated that the program manages the aging effects associated with bolting through material selection and testing, bolting assembly and preload control, operation, maintenance, and the performance of periodic inspections. The applicant stated that the program relies on the performance of periodic inspections and credits other AMPs for the inspection of bolting such as the ASME Code Section XI, ISI, Subsections IWB, IWC, and IWD Program (B.2.1.1). The applicant further stated that the program follows the guidelines and recommendations delineated in the following documents:
| |
| * NUREG-1339, "Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants"
| |
| * EPRI NP-5769, "Degradation and Failure of Bolting in Nuclear Power Plants" (with the exceptions noted in NUREG
| |
| -1339)
| |
| * EPRI TR-104213, "Bolted Joint Maintenance and Application Guide," for comprehensive bolting maintenance. By letter dated August 11, 2017 (a June 20, 2017, letter on the same topic was superseded by the August 11, 2017, letter), the applicant revised the Bolting Integrity Program to address detection of aging effects associated with closure bolting located in air and gas filled systems and systems at internal atmospheric pressure.
| |
| | |
| Aging Management Review Results 3-26
| |
| * Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.M18. As discussed in the AMP audit report, the staff confirmed that each element of the applicant's program is consistent with the corresponding element of GALL Report AMP XI.M18, with the exception of the "parameters monitored or inspected" program element. For this element, the staff determined the need for additional clarification, which resulted in the issuance of an RAI.
| |
| GALL Report AMP XI.M18 recommends that safety
| |
| -related and nonsafety
| |
| -related bolting be inspected for leakage under the "parameters monitored or inspected" program element. However, during its audit, the staff found that there are in
| |
| -scope components in the applicant's fire protection system, service water system, and spent fuel pool cooling system that are in moist or submerged environments for which visual inspection to detect leakage is not feasible due to the environmental conditions. By letter dated November 18, 2010 (ADAMS Accession No. ML103090558), the staff issued RAI B.2.1.9
| |
| -1, requesting that the applicant provide details on how the in
| |
| -scope components in wet environments will be inspected for leakage.
| |
| In its response dated December 17, 2010 (ADAMS Accession No. ML103540534), the applicant stated that the Bolting Integrity Program will be amended to credit the Open
| |
| -Cycle Cooling Water System Program to manage the aging effects of loss of material and loss of preload in submerged in
| |
| -scope bolting; specifically, the service water pump column bolting. The applicant also stated that, through inspections implemented by the Open
| |
| -Cycle Cooling Water System Program, the water pump column bolted connections, which are submerged in raw water, will be visually inspected when the pumps are removed for maintenance. The applicant further stated that a corrective action document has been generated to require inspection for loose or missing in
| |
| -scope bolts. The applicant further stated that the stainless steel bolting in the spent fuel pool cooling system externally exposed to borated water was incorrectly shown as being in
| |
| -scope in LRA Table 3.3.2
| |
| -39. The item was subsequently removed due to the fact that those bolts were reassessed to be out of the scope of license renewal since they are associated with an out
| |
| -ofscope component and provide no pressure boundary function.
| |
| The applicant also stated that the Buried Piping and Tanks Inspection Program will be used to manage aging effects for bolting used in buried, underground, and inaccessible submerged piping. The applicant further stated that, in instances where hydrostatic testing, flow testing, or fire protection jockey pump monitoring are used in lieu of visual inspections, these methods will also be credited to identify leakage caused by loss of preload at bolted connections. The applicant also stated that the Buried Piping and Tanks Inspection Program will be used in conjunction with the ISI Program and the External Surfaces Monitoring Program, which are cited in the LRA as credited for managing the aging effects of bolting.
| |
| The staff finds the applicant's response acceptable because the applicant amended the LRA to manage wet or submerged bolting with AMPs that are appropriate for these specific environments. These AMPs can manage the loss of material through the implementation of periodic and opportunistic visual inspections and loss of preload through hydrostatic testing, flow testing, pump monitoring, visual inspections, and other inspections to detect leakage or loose and missing bolts. In addition, the staff finds the removal of the two items in LRA Table Aging Management Review Results 3-27 3.3.2-39 acceptable and determined that the bolts are out of the scope of license renewal because they are associated with an out
| |
| -of-scope component and provide no pressure boundary function. The staff's concern described in RAI B.2.1.9-1 is resolved.
| |
| By letter dated May 24, 2017, the staff issued RAI B2.1.9
| |
| -3, requesting that the applicant state how aging effects associated with closure bolting located in air
| |
| - and gas-filled systems and systems at internal atmospheric pressure will be managed.
| |
| In its response dated August 11, 2017, the applicant stated that the inspection technique for air
| |
| - or gas-filled systems will be one of the following: (a) visual inspections to detect discoloration when the internal environment would discolor the external surface of the component; (b) monitoring and trending of pressure decay when the component is within an isolable boundary; (c) visual inspections augmented with a soap
| |
| -like solution to promote bubble formation; or (d) thermography if the internal environment is higher than the ambient environment. The applicant also stated that it will conduct a tightness check on 20 percent of the bolts (or a maximum of 25 bolts) for each material and environment combination installed in components exposed to atmospheric pressure conditions. The tightness check will be performed prior to the period of extended operation and once every 10 years after the initial inspections. The applicant added an enhancement to the program to implement the abovedescribed changes. The staff noted that GALL Report AMP XI.M18 recommends conducting leak inspections of closure bolting joints on a refueling outage interval. The staff also noted that checking for tightness results in both an inspection of the bolt head and a direct verification that potential loss of material, cracking, or loss of preload that would affect the intended function of the closure bolting joint is not occurring. The staff finds the response to RAI B.2.1.9
| |
| -3 acceptable because: (a) the proposed inspection methods are capable of detecting leakage in air
| |
| -filled and gas-filled systems, (b) the Bolting Integrity Program conducts inspections on a refueling outage interval consistent with AMP XI.M18, and (c) for closure bolting installed in systems where th e internal environment consists of atmospheric pressure, the test technique is more rigorous than a leak check to justify the longer interval between inspections.
| |
| Based on its audit and review of the application and the applicant's response to RAI B.2.1.9
| |
| -1 and RAI B.2.1.9
| |
| -3, the staff finds that elements one through six of the applicant's Bolting Integrity Program are consistent with the corresponding program elements of GALL Report AMP XI.M18 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.9 summarizes operating experience related to the Bolting Integrity Program. The applicant stated that rust was observed on the pipe supporting bolts of the RH equipment vault, an engineering evaluation was conducted, the rusted condition was determined to not impact the function of the bolts, and the affected area was painted to prevent further degradation. The applicant also stated that galvanic corrosion was detected on the bolting associated with one of the containment air handling coolers, determined to be due to condensation on dissimilar metal interfaces, and the corrective action involved a materials substitution that provided adequate resistance to galvanic corrosion, which removed the susceptibility for further degradation.
| |
| The staff reviewed operating experience information in the application and during the audit to determine whether the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant and are evaluated in the GALL Report. A s discussed in the AMP audit report, the staff conducted an independent search of the plant Aging Management Review Results 3-28 operating experience information to determine whether the applicant had adequately incorporated and evaluated operating experience related to this program. During its review, the staff identified industry operating experience for which it determined the need for additional clarification resulting in the issuance of an RAI, as discussed below.
| |
| The staff lacked sufficient information to conclude that the applicant's program was effective at managing aging of pressure
| |
| -retaining bolting and component external surfaces that are surrounded by seal cap enclosures. The staff noted that, in recent reviews of license renewal applications and operating experience, the applicant may have used, or currently uses, seal cap enclosures to contain water leakage. The staff noted that the use of the enclosures was not accounted for in the LRA. By letter dated May 29, 2012 (ADAMS Accession No. ML12144A441), the staff issued RAI B.2.1.9-2, requesting that, for all pressure
| |
| -retaining bolting and external surfaces that are surrounded by seal cap enclosures, the applicant describe (a) the bolting and component material and the leaking water environment, (b) new AMR items for the aging management of the bolting and external surfaces for loss of material, loss of preload, change in material properties, and cracking due to SCC in the submerged environment, (c) technical justification for how the aging effects above are managed if direct inspection is not possible, and (d) how future use of seal cap enclosures is controlled such that aging is managed. These issues were identified as Open Item OI 3.0.3.1.7
| |
| -1 in the SER with Open Items issued in June 2012.
| |
| In its response to RAI B.2.1.9
| |
| -2, dated June 19, 2012 (ADAMS Accession No. ML12178A405), the applicant stated that a single seal cap enclosure was installed on the SI
| |
| -V-82 swing check valve. The seal cap enclosure was installed during the 2011 outage to allow continued operation of the unit until such time that the valve could be repaired. The applicant also stated that the installation of a seal cap enclosure creates a submerged environment that prevents the aging management of the bolting and component external surfaces for loss of material, loss of preload, cracking, and change in material properties. Therefore, the applicant stated that it planned to remove the seal cap enclosure and restore the valve to its original configuration at the next available opportunity, no later than December 31, 2014. The applicant also stated that it has no plans to install new seal cap enclosures. The staff noted that the applicant revised LRA Section A.2.1.9, "Bolting Integrity" (i.e., UFSAR supplement), to add a description of the seal cap enclosure, as well as a summary of its plan to remove the seal cap enclosure no later than December 31, 2014.
| |
| The staff finds the applicant's response acceptable because the applicant stated that it will remove the seal cap enclosure no later than December 31, 2014, and it will return the valve to its original configuration. The staff noted that the plan to restore the valve to its original configuration will require the applicant to replace the entire valve, along with associated inspections to ensure that the original configuration has been achieved. The staff also noted that after the seal cap enclosures have been removed, the bolted joint will be exposed to an environment of treated borated water leakage, as is currently described in the LRA, and will be age managed during the period of extended operation by the Boric Acid Corrosion and Bolting Integrity AMPs, consistent with the GALL Report guidance. The staff finds that the revision of the UFSAR supplement, to include a summary description of the seal cap enclosure and the plan to remove it and restore it to its original condition no later than December 31, 2014, provides additional assurance that the seal cap enclosure will be removed as described. The staff's concern described in RAI B.2.1.9
| |
| -2 is resolved, and Open Item OI 3.0.3.1.7
| |
| -1 is closed.
| |
| | |
| Aging Management Review Results 3-29 By letter dated December 10, 2012 (ADAMS Accession No. ML12349A214), the applicant stated that the seal cap enclosure from SI
| |
| -V-82 was removed and the associated valve was replaced in the fall of 2012, during RFO 15. Based on its audit, the review of the application, and the closure of Open Item OI 3.0.3.1.7
| |
| -1, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10 and, therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.9, as amended by letters dated June 19, 2012, and December 10, 2012, provides the UFSAR supplement for the Bolting Integrity Program. The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Tables 3.1
| |
| -2, 3.2-2, 3.3-2, 3.4-2, and 3.5
| |
| -2. The staff also noted that the applicant committed (Commitment 51) to incorporate the changes described in the response to RAI B2.1.9
| |
| -3 prior to the period of extended operation. The staff determined that the information in the UFSAR supplement, as amended, is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its review of the applicant's Bolting Integrity Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.1.8 One-Time Inspection Program Summary of Technical Information in the Application. LRA Section B.2.1.20 describes the new One-Time Inspection Program as consistent with GALL Report AMP XI.M32, "One
| |
| -Time Inspection." The applicant stated that the One
| |
| -Time Inspection Program is a new program that addresses component, material, and environment combinations for which aging effects are either not occurring or are progressing so slowly as to have negligible effect on the intended function of the structure or components through the period of extended operation. The applicant also stated that the program will provide the following functions:
| |
| * determination of appropriate inspection sample size
| |
| * identification of inspection locations
| |
| * selection of examination techniques, including acceptance criteria
| |
| * evaluation of results to determine the need for additional inspections or other corrective actions The applicant further stated that the inspection methods of the program may include visual (or remote visual), surface, or volumetric examinations, or other established nondestructive examination techniques.
| |
| | |
| Aging Management Review Results 3-30 Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.M32. As discussed in the audit report, the staff confirmed that these elements are consistent with the corresponding elements of GALL Report AMP XI.M32, with the exception of the "detection of aging effects" program element. In this element, the staff determined the need for additional clarification, which resulted in the issuance of an RAI. GALL Report AMP XI.M32 states that the inspection includes a representative sample of the system population, and, where practical, focuses on the bounding or lead components most susceptible to aging due to time in service, severity of operating conditions, and lowest design margin. However, during the staff's review of the applicant's One
| |
| -Time Inspection Program, the staff noted that the applicant did not include specific information regarding how the sample set of components are to be selected or how the sample size will be determined. The staff also noted that large sample sizes (e.g., at least 20 percent) may be necessary in order to adequately confirm an aging effect does not occur because of the uncertainty in determining the most susceptible locations and the potential for aging to occur in other locations.
| |
| By letter dated December 14, 2010 (ADAMS Accession No. ML103420273), the staff issued RAI B.2.1.20-1, requesting that the applicant provide specific information regarding how the sample set of components will be selected and how the size of the sample of components will be determined.
| |
| In its response dated January 13, 2011 (ADAMS Accession No. ML110140587), the applicant stated that the program will be modified to include the inspection of approximately 20 percent of the components of each in
| |
| -scope material type, environment, and aging effect combination, but not to exceed 25 components. The staff noted that LRA Section B.2.1.20 states that the samples include locations where the most severe aging effects would be expected to occur. The samples will be based on aspects such as location, design, material of construction, service environment, and previous failure history, and they will include stagnant or low
| |
| -flow areas. The staff finds the applicant's response acceptable because the applicant's sampling methodology ensures a representative sample of material and environment combinations is considered, ensures sample locations will focus on the most susceptible components, and includes an appropriate sample size. The staff's concern described in RAI B.2.1.
| |
| 20-1 is resolved.
| |
| Based on its audit and review of the application and the applicant's response to RAI B.2.1.20
| |
| -1, the staff finds that elements one through six of the applicant's One
| |
| -Time Inspection Program are consistent with the corresponding program elements of GALL Report AMP XI.M32 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.20 summarizes operating experience related to the One-Time Inspection Program. The applicant stated that there is no operating experience specifically applicable to the new one
| |
| -time inspections. However, the applicant provided examples of operating experience that indicated the existing Condition Monitoring and Condition Reporting Programs are effective in identifying, evaluating, and correcting aging effects typical of the scope of this program. For example, the applicant described an instance in which corrosion was observed on the pump discharge head flange during the replacement of Aging Management Review Results 3-31 a service water cooling tower pump. In response to the observed corrosion, the discharge head was replaced with a more corrosion
| |
| -resistant material.
| |
| In another instance of operating experience, the applicant described a case in which a large amount of rust and scale was found in piping connecting valves with air receivers. The applicant stated that the response involved removal of all loose corrosion products, and no evidence of pitting or wall thinning was found.
| |
| The staff reviewed operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program.
| |
| During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.20 provides the UFSAR supplement for the One
| |
| -Time Inspection Program. The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Tables 3.1
| |
| -2, 3.2-2, 3.3-2, and 3.4
| |
| -2. The staff also noted that in LRA Supplement 2 to the LRA, Appendix A, the applicant committed (Commitment 22) to implement the new One
| |
| -Time Inspection Program within 10 years prior to the period of extended operation. The staff determined that the information in the UFSAR supplement, as amended, is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its review of the applicant's One
| |
| -Time Inspection Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.1.9 ASME Code Section XI, Subsection IWE Aging Management Program Summary of Technical Information in the Application. LRA Section B.2.1.27, as revised by letter dated August 11, 2011 (ADAMS Accession No. ML11227A023), describes the existing ASME Code Section XI, Subsection IWE AMP, as consistent, with an enhancement, with GALL Aging Management Review Results 3-32 Report AMP XI.S1, "ASME Section XI, Subsection IWE." The LRA states that this program manages aging effects of the containment steel liner plate, electrical penetrations, mechanical penetrations (piping, ventilation, and spares), personnel lock, equipment hatch, recirculation sump, reactor pit, moisture barriers, seals, gaskets, pressure
| |
| -retaining bolting, and supports.
| |
| Inspection of the containment liner plate and the associated components are performed in accordance with ASME Code Section XI, Subsection IWE. The applicant also stated that the acceptance criteria, corrective actions, and expansion of the inspection scope when degradation exceeding the acceptance criteria is found are in accordance with the IWE requirements. According to the LRA, the applicant followed the requirements of the 1995 Edition, including the 1996 Addenda, of ASME Code Section XI, Subsection IWE for the first 10-year inspection interval effective from August 19, 2000
| |
| -August 18, 2010, and in accordance with 10 CFR 50.55a. The applicant also stated that the next and subsequent 120
| |
| -month inspection interval will incorporate the requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a, 12 months before the start of the inspection interval.
| |
| During the course of the staff's review, the applicant submitted amendments to the application, and these are discussed in the staff's evaluation below, as appropriate.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.S1. As discussed in the audit report, the staff confirmed that these elements are consistent with the corresponding elements of GALL Report AMP XI.S1.
| |
| The staff also reviewed the portions of the program associated with the enhancement to determine if the program will be adequate to manage the aging effects for which it is credited. The staff's evaluation of this enhancement follows.
| |
| Enhancement 1. LRA Section B.2.1.27, as revised by letters dated December 17, 2010, April 14, 2011, August 11, 2011, and October 2, 2014, describes an enhancement to AMP XI.S1. The staff notes that this enhancement and the associated Commitment 50 were provided by the applicant in response to concerns associated with RAI B.2.1.27
| |
| -1. The staff's concerns related to RAI B.2.1.27
| |
| -1 are resolved and fully discussed below in the evaluation of the AMP operating experience. The applicant stated that the program will be enhanced as follows:
| |
| NextEra Energy Seabrook commits to initiating a confirmatory examination process to initially and periodically verify the soundness of the liner plate. The confirmatory process will include ultrasonic thickness (UT) examinations of 360° of the accessible liner plate in a band extending from the moisture barrier at el. -26', to ten inches above the moisture barrier. The examination process will perform 50 UT's at approximately equal spacing around the accessible circumference of the liner plate as discussed above.
| |
| NextEra Energy Seabrook will conduct confirmatory UT examinations of the containment liner plate in the vicinity of the moisture barrier for loss of material Aging Management Review Results 3-33 within the next two refueling outages, [RFO]15 or [RFO]16. In the absence of any positive indication of material loss being identified during the initial examination, confirmatory examinations will be repeated at five refueling outage intervals.
| |
| The staff noted that, by letter dated October 2, 2014 (ADAMS Accession No. ML14282A023), the applicant stated that it completed baseline UT of the containment liner plate during its April 2014 RFO 16 and found no evidence of loss of material. The staff finds the program enhancement acceptable because the augmented UT examination will provide reasonable assurance that any potential loss of material at the containment liner plate due to water accumulating in the annulus area will be identified and timely addressed before there is a loss of intended function for the containment liner plate. Based on its audit and review of the application, as revised, the staff finds that elements one through six of the applicant's ASME Code Section XI, Subsection IWE AMP, are consistent with the corresponding program elements of GALL Report AMP XI.S1 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.27 summarizes operating experience related to the ASME Code Section XI, Subsection IWE AMP. The applicant stated it has reviewed the industry operating experience concerning containment liner plate degradation, including NRC Information Notice (IN) 86
| |
| -99, "Degradation of Steel Containments"; IN 88
| |
| -82, "Torus Shells with Corrosion and Degraded Coatings in BWR Containments"; IN 89
| |
| -79, "Degraded Coatings and Corrosion of Steel Containment Vessels," and IN 97
| |
| -10, "Liner Plate Corrosion in Concrete Containments," and considered their applicability to Seabrook. The applicant also stated that it has reviewed the containment liner issue from Beaver Valley, where inspections in 2009 revealed degradation from the inaccessible side of the steel liner. The applicant further stated that no potentially through
| |
| -liner corrosion issues have been noted during the IWE examinations.
| |
| In LRA Section B.2.1.27, the applicant identified several condition reports documenting material found to be in contact with the containment liner (e.g., scaffolding, grating hose reels, and outage contractor storage boxes) during outage activities. The applicant further stated that "these were promptly and appropriately dispositioned." In addition, the applicant stated that, during the Seabrook nuclear oversight audit of key activities during RFO 7 (fall 2000), one material was observed as a faulty moisture barrier at the minus 26
| |
| -ft level, azimuth 250°. A condition report was initiated and documented as part of the applicant's corrective action program; the barrier was repaired. The applicant also stated that, in November 2001, a condition report documented the opportunity to complete IWE examinations for the containment recirculation sump area during the RFO window for containment liner inspection that had been inaccessible. The applicant stated that "this condition report document[s] the understanding of the scope of this program and the ability to recognize respective windows of opportunity."
| |
| The staff reviewed operating experience information in the application and during the audit, to determine if the applicable aging effects and industry and pl ant-specific operating experience were reviewed by the applicant. As discussed in the AMP audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program. During its review, the staff identified operating experience that could indicate that the applicant's program may not be effective in adequately managing aging effects during the period of extended operation. The staff determined the need for additional clarification, which resulted in the issuance of RAIs.
| |
| | |
| Aging Management Review Results 3-34 During the AMP audit, the staff interviewed the applicant's staff and reviewed documentation about the groundwater seepage in different plant structures. The staff found that, previously, groundwater had infiltrated into the annular space between the concrete enclosure building and concrete containment. The bottom 6 ft of the concrete containment wall was in contact with the groundwater for an extended period of time. In addition, cracks due to alkali
| |
| -silica reaction (ASR) have been observed in various Seabrook plant concrete structures, including the concrete enclosure building. Therefore, the groundwater may have penetrated the concrete containment wall and come into contact with the containment liner plate. The staff was concerned that water seepage through cracks in the concrete containment could result in through-wall corrosion of the containment liner plate. Therefore, in a letter dated November 18, 2010 (ADAMS Accession No. ML103090558), the staff issued RAI B.2.1.27
| |
| -1, requesting that the applicant explain any plans to perform nondestructive examinations, such as UT, of the containment liner to measure the liner thickness and demonstrate that the effects of prolonged exposure of the bottom portion of the concrete containment to groundwater have not introduced corrosion on the concrete side of the liner plate. Corrosion on the concrete side of the containment liner could affect its ability to perform its intended design function during the period of extended operation.
| |
| In its response, dated December 17, 2010 (ADAMS Accession No. ML103540534), the applicant stated that Seabrook continues to monitor the annulus area, including the exterior concrete surface of containment where groundwater had accumulated. The applicant also stated that the lack of oxygen and high pH alkaline environment of the concrete are inhibitors to a corrosive environment that would be detrimental to the integrity of the liner; therefore, the potential for loss of material at the concrete
| |
| -to-liner plate interface due to water accumulating in the annulus area is very low. However, based on NRC IN 2010
| |
| -12, "Containment Liner Corrosion," and other industry and site
| |
| -specific operating experience, Seabrook will perform testing of the containment liner plate for loss of material. The applicant added an enhancement and a commitment (Commitment 50) to its ASME Code Section XI, Subsection IWE AMP, to perform testing of the containment liner plate for loss of material on the concrete side of the liner. The testing will be conducted in accordance with approved ASME Code Section XI, Subsection IWE, methodology, and it will be completed prior to the period of extended operation. In addition, the applicant committed (Commitment 52) to put measures in place to maintain the exterior surface of the containment structure from elevation
| |
| -30 ft to +20 ft in a dewatered state (by letter dated December 10, 2012 [ADAMS Accession No. ML12349A214], the applicant revised Commitment 52 to reflect implementation on an ongoing basis).
| |
| The staff reviewed the applicant's response to RAI B.2.1.27
| |
| -1 and noted that the applicant committed to perform testing of the containment liner plate for the loss of material on the concrete side of the liner; however, it was not clear how this testing will be performed. Therefore, in a letter dated March 17, 2011 (ADAMS Accession No. ML110350630), the staff issued followup RAI B.2.1.27
| |
| -1 requesting that the applicant provides details regarding the testing to be performed to determine the loss of material on the concrete side of the liner plate. The staff asked: (a) for the details to include a description of the nondestructive testing methods and locations where thickness measurements will be obtained and (b) the applicant to explain why the measurement locations will provide an adequate representation of liner plate locations that may be degraded.
| |
| In its response, dated April 14, 2011 (ADAMS Accession No. ML11108A131), the applicant stated that Seabrook will perform testing (i.e., UT) of the liner plate inside containment for loss Aging Management Review Results 3-35 of material on the concrete side of the liner. The testing will be subject to ASME Code Section XI, Subsection IWE, acceptance criteria (at the time of this response the code in use at Seabrook was the 2004 ASME Code) and will be completed by December 31, 2015. The applicant further stated: "under IWE 1241(a), Seabrook will designate the area of the containment liner that is within 10 in. of the moisture barrier at the containment basement floor for examination. This is the lowest accessible point on the liner - [f]or potential degradation due to moisture, the lowest point is the most susceptible." The applicant stated that examination will be at locations spaced at 10° increments (approximately every 12 ft) of accessible circumference or locations showing visible signs of degradation will be tested (examined), with one or more readings taken at each location. The applicant stated that the examinations will be repeated at intervals of no more than five RFOs. The applicant stated that, if any indications are found that show a loss of material exceeding 10 percent of nominal thickness (ASME Code acceptance criteria), an engineering evaluation of deficient indications will be performed and corrective actions planned accordingly. The applicant revised the enhancement and Commitment 50 to perform UT in the vicinity of the moisture barrier for loss of material at a nominal 10° increment around the circumference of containment, and to complete it no later than December 31, 2015. The UT will be repeated at intervals of no more than five RFOs. The applicant also revised Commitment 50 to clarify the type, location, and schedule for testing.
| |
| The staff reviewed the applicant's response to followup RAI B.2.1.27
| |
| -1 and noted that the applicant stated that it would be performing the examination at an area of the containment liner within 10 in. of the moisture barrier at the containment floor designated in accordance with IWE
| |
| -1241(a). IWE
| |
| -1241(a) requires augmented examination of the containment liner surface area in accordance with Table IWE
| |
| -2500-1, examination Category E
| |
| -C. In further review of IWE
| |
| -1241(a), the staff also noted that item E.4.12 of Table IWE-2500-1 requires 100 percent UT measurement of the area designated for augmented examination during each inspection period until the areas examined remain essentially unchanged for three consecutive inspection periods. The staff was not clear as to whether the applicant planned to follow ASME Code requirements for augmented examinations of the containment liner. By letter dated June 29, 2011 (ADAMS Accession No. ML11178A338), the staff issued a second followup RAI to RAI B.2.1.27
| |
| -1, requesting that the applicant provide technical justification for deviating from In its response dated August 11, 2011 (ADAMS Accession No. ML11227A023), the applicant stated that the area subject to the UT examination has not exhibited any evidence that indicates loss of material or conditions that would cause accelerated degradation, so the containment liner plate in the vicinity of the moisture barrier does not require an ASME Code Section XI, Subsection IWE, repair or augmented examination per IWE
| |
| -1241(a). The applicant stated that its "[RFO] 14 - Containment Liner Examination Summary, dated May 1, 2011, reported 83 indications found in the vicinity of the moisture barrier. These 83 indications in the vicinity of the moisture barrier were on the concrete floor, the moisture barrier, and the containment liner." The applicant stated that all of the indications were minor, less than 1 square inch in area, and that conditions "[do] not meet the requirements of IWE
| |
| -1240 for augment[ed] examination" so augmented examinations are not required. The applicant stated that (a) it evaluated all of the indications through the corrective action process and (b) the indications found in RFO 14 have been either accepted or corrective actions taken, or scheduled, for remediation in RFO 15. With regards to the UT of the containment liner, the applicant stated that the testing is confirmatory only and that the testing will confirm no loss of material of the liner plate around the moisture barrier. The applicant revised its enhancement to the IWE program to clarify that it will perform confirmatory examinations to periodically verify the soundness of the containment Aging Management Review Results 3-36 liner plate. It also revised the previous plans to perform the examination at 10° increments around the containment circumference, and instead stated it will perform 50 UTs at approximately equal spacing around the containment. The applicant changed Commitment 50 to perform the examination "no later than December 31, 2015" to "[w]ithin the next two R[F]Os, R[F]O 15 or R[F]O 16." Based on its review, the staff finds the applicant's response acceptable because the applicant committed to monitor the containment liner plate condition and thickness (a) prior to December 31, 2015, and (b) subsequently at intervals of no more than five RFOs (7.5 years) before and during the period of extended operation. The UT will be performed at 50 locations around the circumference of containment. The augmented UT examination, in conjunction with the visual examinations in accordance with IWE, will provide reasonable assurance that any potential loss of material at the concrete
| |
| -to-liner-plate interface due to water accumulating in the annulus area will not affect the structural integrity of the containment liner plate. In case loss of liner plate thickness is detected during the visual and UT examinations, the applicant will perform an engineering evaluation and will perform remedial actions in accordance with the corrective action program. The applicant's Commitment 50 also demonstrates that the applicant addressed operating experience identified after issuance of the GALL Report, including IN 2010
| |
| -12, concerning through
| |
| -wall corrosion of the liner plate at Beaver Valley Power Station. The staff's concerns in RAI B.2.1.27
| |
| -1 and the associated followup RAIs concerning liner plate corrosion and loss of material are resolved.
| |
| By letter dated October 2, 2014 (ADAMS Accession No. ML14282A023), in its fourth annual update to the LRA, the applicant stated that it completed baseline UT of the containment liner plate during its RFO 16 (April 2014). The applicant also stated that thickness measurements were taken at a total of 51 locations in accessible areas in the vicinity above the moisture barrier. The applicant further stated that the observed thickness met the minimum thickness requirements of ASME Code Section XI, IWE
| |
| -3122.3(a), with no evidence of loss of material due to corrosion. The applicant stated that actions have been created and assigned in its corrective action process to repeat UT of the containment liner plate at intervals of no more than five RFOs and to perform UT on inaccessible areas when opportunities arise. Accordingly, the applicant revised the wording of Commitment 50 to clarify that the applicant will perform UT of the accessible areas of the containment liner plate in the vicinity of the moisture barrier for loss of material and opportunistic UT of inaccessible areas. The applicant also revised the implementation schedule to document completion of the baseline confirmatory UT of the containment liner plate, which was performed during RFO 16, and indicate that containment liner UT thickness examinations will be repeated at intervals of no more than five RFOs.
| |
| The staff reviewed the applicant's revised Commitment 50 and notes that the clarification made to differentiate between accessible and inaccessible areas is appropriate. The staff also notes that the baseline inspection of the containment liner plate in the vicinity of the moisture barrier was performed during RFO 16. The staff finds the applicant's revisions to Commitment 50 acceptable because the baseline UT identified no evidence of loss of liner material; for this confirmatory testing, it is reasonable to perform UT on the accessible portions of the containment liner; and for the inaccessible areas, the applicant has created and assigned actions through its Corrective Action Program to perform UT of the inaccessible areas when opportunities arise.
| |
| | |
| Aging Management Review Results 3-37 The staff also noted that, in response to RAI B.2.1.28
| |
| -3, revised by letter dated April 14, 2011 (ADAMS Accession No. ML11108A131), the applicant committed (Commitment 52) to implement measures to maintain the containment exterior surface between elevations
| |
| -30 ft to +20 ft dewatered by December 31, 2012. During the December 31, 2010, inspection, NRC inspectors examined the subject area and found it in a dewatered state. NRC inspectors also noted that portable sump pumps are used to dewater the area. However, the staff was concerned that the applicant had not implemented any permanent measures for dewatering or revised its procedures for routine inspection of this area to ensure that the area remained dewatered. Accumulation of water in the annular space between the containment and containment enclosure buildings can potentially degrade the containment liner plate. The staff's concern was tracked as Open Item OI 3.0.3.1.9
| |
| -1. In a letter dated December 10, 2012 (ADAMS Accession No. ML12349A214), the applicant revised Commitment 52 and committed to putting measures in place to maintain the subject area in the dewatered state on an ongoing basis. By letter dated June 30, 2015 (ADAMS Accession No. ML15183A023), the applicant confirmed that the ongoing dewatering activities, as delineated by Commitment 52, have been incorporated into the station's preventive maintenance program to specifically maintain the containment structure in a dewatered state.
| |
| Therefore, the staff concerns related to degradation of the containment liner plate due to the presence of groundwater in the annular space between the containment and containment enclosure building is resolved. Open Item OI 3.0.3.1.9
| |
| -1 is closed.
| |
| During the site audit, the staff reviewed documentation concerning the corrosion of the containment liner plate around the fuel transfer tube vault documented during the 2009 IWE inspection. The containment liner plate had indications of heavy corrosion. UT examination of the containment liner indicated that liner plate thickness varied between 0.484
| |
| -0.411 in. (variation of 18 percent) within a small area. The applicant accepted this degradation of the liner plate based on engineering evaluation. The applicant's justification for acceptance was that the measured thickness of the liner plate was still greater than the 0.375
| |
| -in. nominal thickness of the liner plate. However, the staff did not find any requirement in the applicant's engineering evaluation that requires UT reexamination of the affected portion of the liner plate for three consecutive periods in accordance with IW E-2420 (i.e., the augmented examination requirements of ASME Code Section XI, Subsection IWE
| |
| -2420). The staff was not clear as to whether the applicant followed the requirements of the ASME Code for augmented examination of the containment liner plate and needed further information to determine whether this was an area that should be designated for augmented examination and, if so, whether the requirements of the ASME Code were being followed. Therefore, in a letter dated November 18, 2010 (ADAMS Accession No. ML103090558), the staff issued RAI B.2.1.27
| |
| -2, requesting that the applicant provide the details of any actions planned for augmented examination of the containment liner plate around the fuel transfer tube where the corrosion was detected during the 2009 inspection.
| |
| In its response, dated December 17, 2010 (ADAMS Accession No. ML103540534), the applicant stated that this condition requires augmented inspection in accordance with the 1995 Edition with 1996 Addenda of the ASME Boiler and Pressure Vessel (B&PV) Code, Section XI, Subsections IWE
| |
| -2420(b) and IWE
| |
| -2420(c). The applicant further stated that the condition has been identified in the ISI Program database for reexamination during subsequent scheduled inspections.
| |
| | |
| Aging Management Review Results 3-38 The staff reviewed the applicant's response to RAI B.2.1.27
| |
| -2 and noted that the applicant stated that it would perform augmented examinations in accordance with the ASME Code; however, the staff also noted that the ASME Code 1995 Edition with 1996 Addenda, Section XI, Subsections IWE
| |
| -2420(b) and IWE
| |
| -2420(c), state that reexamination of degraded areas is no longer required if these areas remain essentially unchanged for three consecutive inspection periods. Further, it was not clear from the applicant's response if the containment liner plate around the fuel transfer tube is still exposed to the borated water leakage. The staff was concerned that exposure to borated water can promote corrosion of the liner plate and adversely affect the ability of the liner to perform its intended function. Therefore, in a letter dated March 17, 2011 (ADAMS Accession No. ML110350630), the staff issued followup RAI B.2.1.27-2 requesting that the applicant describe (a) steps that are being taken to monitor the liner plate thickness around the transfer tube, or (b) efforts to address the leakage of borated water, or (c) both (a) and (b).
| |
| In its response, dated April 14, 2011 (ADAMS Accession No. ML11108A131), the applicant stated that the leak path into the fuel transfer tube vault has been repaired and the borated water leakage has stopped. The area of the containment liner plate that had showed signs of deficiency (loss of material) has been examined and accepted by engineering evaluation. The areas are subject to IWE
| |
| -required augmented UT examinations for the next three exam cycles. If no further degradation (loss of material) is observed during those three cycles, the subject area will return to normal visual IWE inspections. These visual inspections would be able to identify any further leakage of borated water.
| |
| The staff reviewed the applicant's response to followup RAI B.2.1.27
| |
| -2, dated March 17, 2011, and noted that (1) the applicant did not provide information regarding when UT examinations had been conducted or the results of the examinations, (2) it was unclear whether the containment liner plate area below the fuel transfer tube that has been exposed to the borated water leakage is designated for augmented examination in accordance with IWE
| |
| -1241(a), and (3) there was no information regarding the timing for the initial and three subsequent consecutive examinations in accordance with IWE requirements for augmented examinations. Therefore, by letter dated June 29, 2011 (ADAMS Accession No. ML11178A338), the staff issued followup RAI B.2.1.27
| |
| -2, requesting that the applicant provide the dates and results of the UT examinations of the containment liner plate area below the fuel transfer tube. The staff also requested that the applicant explain, if any of the values were below the minimum wall thickness, how the areas were repaired or evaluated.
| |
| By letter dated August 11, 2011 (ADAMS Accession No. ML11227A023), the applicant responded to followup RAI B.2.1.27
| |
| -2, dated March 17, 2011, and stated:
| |
| The containment liner plate at the fuel transfer tube penetration (PEN
| |
| -X62) subject to a VT
| |
| -3 examination under Subsection IWE on October 15, 2009. Five indications were subjected to UT examination, power tool cleaned, and recoated. None of these indications had measured values less than nominal wall thickness, however, the area was incorrectly designated for ASME Section XI, Subsecti on IWE-1241 augmented inspection.
| |
| The applicant also stated:
| |
| The first of three planned consecutive augmented inspections was performed in
| |
| | |
| Aging Management Review Results 3-39 April 2011. The entire surface area at the fuel transfer tube penetration (PEN
| |
| -X62) was subjected to visual examination, and areas around the five indications identified in October 2009 were subjected to UT scans. The area of the prior minimum thickness reading of 0.411 inches was re
| |
| -measured as ranging from 0.400 to 0.409 inches. The thickness measured is greater than t nom (0.375 inches); no repairs are required.
| |
| Based on its review, the staff finds the applicant's responses to RAI B.2.1.27
| |
| -2 and followup RAIs acceptable because the applicant evaluated the local loss of thickness and degradation in the liner plate around the fuel transfer tube and found it acceptable. However, the staff noted that the applicant had incorrectly identified this degradation in its ISI Program database for reexamination during the next three exam cycles in accordance with IWE
| |
| -2420 requirements. The staff noted that subsequent to completing the first of three planned consecutive augmented inspections, the applicant evaluated the areas and found that they do not require augmented examinations per the ASME Code, and therefore, the applicant is not required by the ASME Code to perform UT examinations of the area in the following two consecutive RFOs. In addition, the applicant repaired the leak path into the fuel transfer tube vault to stop the borated water leakage.
| |
| By letter dated June 24, 2014 (ADAMS Accession No. ML14177A502), the applicant revised its response to RAI B.2.1.27
| |
| -2, dated April 14, 2014, stating in part:
| |
| At the time the response to the request for additional information was submitted, the liner plate was identified as being Category E
| |
| -C in accordance with IWE
| |
| -2420(b)- Upon subsequent review, it was determined that this area did not meet the requirements for Category E
| |
| -C augmented inspections and was reclassified. The original coating indications and minor surface corrosion will not reoccur since the leakage into the vault was successfully remediated during OR11 [i.e., RFO11] in October 2006. The areas of concern on the containment liner plate that were originally identified were examined and accepted in October 2009 (via IWE
| |
| -VT-3 Examination and UT thickness measurements).
| |
| The applicant also revised its April 14, 2011, response to RAI B.2.1.27
| |
| -2 to remove the discussion of the need for augmented UT examinations for the next three exam cycles per the requirements of ASME Code Section XI, Subsection IWE, and replaced it with the above discussion, clarifying that the areas were evaluated and found not to meet the ASME Code criteria for augmented examination.
| |
| The staff reviewed the applicant's (a) August 11, 2011, response to RAI B.2.1.27
| |
| -2 and (b) June 24, 2014, revision to the April 14, 2011, response to RAI B.2.1.27
| |
| -2. The staff noted that the applicant, per the ASME Code Section XI, Subsection IWE, inspection requirements identified areas that could be indicative of a loss of material due to corrosion. The applicant followed the ASME Code and performed an evaluation to identify whether the areas should be subject to augmented examination.
| |
| During a teleconference held on September 30, 2014 (ADAMS Accession No. ML14301A304), the applicant further clarified its April 14, 2011, August 11, 2011, and June 24, 2014, responses and confirmed that the inspections of the containment liner plate in April 2011 were performed in accordance with the augmented examination requirements of IWE 1241(a), and prior to a subsequent review that determined that the areas were incorrectly designated for augmented Aging Management Review Results 3-40 examination. That is, the remaining two originally planned subsequent inspections are not required to be performed because the areas of concern were examined and accepted in 2009, and the areas did not meet the ASME requirements for augmented examination. However, the areas are still subject to the requirements of the ASME Code for visual inspection of the containment liner. The staff finds this acceptable because the applicant is performing examinations and evaluations based on the ASME Code requirements for identification and corrective actions for degradation of the containment liner. The examinations in accordance with IWE requirements will ensure that the containment liner aging is managed in accordance with the guidance provided in GALL Report AMP XI.S1. The staff's concerns in RAI B.2.1.27
| |
| -2 and the associated followup RAI are resolved.
| |
| Based on its audit and review of the application and review of the applicant's responses to RAI B.2.1.27
| |
| -1, RAI B.2.1.27
| |
| -2, and followup RAIs, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program. The staff also finds that implementation of the program has resulted in the applicant taking appropriate corrective actions. The staff confirmed that the "operating experience" program element satisfies th e criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.27 provides the UFSAR supplement for the ASME Code Section XI, Subsection IWE, Aging Management Program. The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Table 3.5
| |
| -2. The staff also noted that the applicant committed (Commitment 50) to performing UT in the vicinity of the moisture barrier for loss of material during RFOs 15 or 16, and repeating at intervals of no more than five RFOs. The staff notes that, by letter dated October 2, 2014, the applicant documented the completion of the baseline inspection of the containment liner plate in the vicinity of the moisture barrier during RFO 16. The applicant has also committed (Commitment 52) to keeping the annular space between the containment and containment enclosure buildings in a dewatered state on an ongoing basis. The staff also notes, that by letter dated June 30, 2015, the applicant confirmed that the ongoing dewatering activities described in Commitment 52 have been incorporated into the station's preventive maintenance program to specifically maintain the containment structure in a dewatered state.
| |
| The staff determined that the information in the UFSAR supplement, as amended by letter dated October 2, 2014, is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its review of the applicant's ASME Code Section XI, Subsection IWE Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.1.10 ASME Code Section XI, Subsection IWF Program
| |
| | |
| Aging Management Review Results 3-41 Summary of Technical Information in the Application. LRA Section B.2.1.29 describes the existing ASME Code Section XI, Subsection IWF, as consistent with GALL Report AMP XI.S3, "ASME Section XI, Subsection IWF." In the LRA, the applicant stated that this program manages aging effects of the ASME Code Classes 1, 2, 3, and metal containment component supports. The Seabrook ASME Code Section XI, Subsection IWF Program, is implemented on a 10-year cycle in accordance with the requirements of 10 CFR 50.55a, with specified limitations, modifications, and NRC
| |
| -approved alternatives. The program specifies the percentage of supports that must be examined. For supports, other than piping supports, the supports of only one component of a group having similar design, function, and service are examined. The applicant also stated that the program uses VT
| |
| -3 visual examination for detection of degradation and uses the acceptance standards for visual examination specified in ASME Code Section XI, Subsection IWF
| |
| -3410. Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.S3. As discussed in the audit report, the staff confirmed that these elements are consistent with the corresponding elements of GALL Report AMP XI.S3. Based on its audit and review of the application, the staff finds that elements one through six of the applicant's ASME Code Section XI, Subsection IWF Program, are consistent with the corresponding program elements of GALL Report AMP XI.S3 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.29 summarizes operating experience related to the ASME Code Section XI, Subsection IWF Program. In the LRA, the applicant stated that an operating experience review found instances of supports being deficient but operable. These conditions were reported and evaluated in accordance with the corrective action program. The LRA also states that IWF Program inspections in the spring of 1997 and spring of 1999 resulted in 36 and 5 deficiencies, respectively. The applicant stated that these conditions were evaluated and dispositioned. During the spring of 2005 inspection, no deficiencies requiring further evaluation were identified.
| |
| The staff reviewed operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program.
| |
| During its review, the staff identified operating experience that could indicate that the applicant's program may not be effective in adequately managing aging effects during the period of extended operation. The staff determined the need for additional clarification, which resulted in the issuance of an RAI.
| |
| The GALL Report AMP XI.S3 states that the IWF scope of inspection for supports is based on sampling of the total support population. Discovery of support deficiencies during regularly scheduled inspections triggers an increase of the inspection scope in order to ensure that the full extent of the deficiencies is identified. IWF
| |
| -2430 provides guidance on how to increase the sample size in case deficiencies are identified during examination of the supports. However, during the audit, the staff did not find any documentation that the supports sample size was Aging Management Review Results 3-42 increased in accordance with IWF-2430 after the ISI inspections conducted during 1997 and 1999, which identified 36 and 5 support conditions with deficient conditions, respectively.
| |
| Therefore, to address this issue, by letter dated November 18, 2010 (ADAMS Accession No. ML103090558), the staff issued RAI B.2.1.29
| |
| -1, requesting that the applicant provide documentation demonstrating IWF inspections are performed in accordance with the recommendations of GALL Report XI.S3 regarding increase in the sample size when deficiencies are identified during examination of supports.
| |
| In its response dated December 17, 2010 (ADAMS Accession No. ML103540534), the applicant stated that, during the 1997 IWF (RFO 05) Inspection, 36 apparent deficiencies were identified. All 36 were evaluated by the applicant engineering personnel. Of the 36 deficiencies, 32 were suspect clearances that were found acceptable, 2 were determined to be design issues (which were corrected), and 2 were evaluated as deficiencies that were repaired to acceptable condition. For these last two deficiencies, the applicant conducted expanded inspections. The applicant also stated that the 32 clearance deficiencies noted above were identified on the basis of ISI drawings, which gave an absolute value for clearance. The applicant further stated that the engineering evaluation that evaluated the clearances against tolerances of the design and construction specifications, found the conditions to be nonrelevant in accordance with IWF
| |
| -3410(b). Therefore, no corrective action was called for and an extended examination was not required. Similar results for clearance deficiencies were seen and dispositioned during the following, 1999 IWF Inspection.
| |
| The staff reviewed the applicant's response to the RAI B.2.29
| |
| -1 and found it acceptabl e because the applicant expanded the scope of inspections for the two supports that were found deficient and repaired them, as required by ASME Code Section XI, Subsection IWF. The supports with clearance deficiencies were found to be acceptable after review of design drawings. IWF
| |
| -3410 considers general conditions that are acceptable by the material, design, or construction specifications as nonrelevant. Expanded scope, in accordance with IWF
| |
| -3410, is not required for nonrelevant conditions. The staff's concern in RAI B.2.1.29
| |
| -1 is resolved.
| |
| Based on its audit and review of the application, and review of the applicant's response to RAI B.2.1.29-1, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking appropriate corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.29 provides the UFSAR supplement for the ASME Code Section XI, Subsection IWF Program.
| |
| The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Table 3.5-2. The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its review of the applicant's ASME Code Section XI, Subsection IWF Program, and RAI B.2.1.29
| |
| -1 response, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant demonstrated that the Aging Management Review Results 3-43 effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.1.11 10 CFR Part 50, Appendix J Aging Management Program Summary of Technical Information in the Application. LRA Section B.2.1.30 describes the existing 10 CFR Part 50, Appendix J AMP as consistent with GALL Report AMP XI.S4, "10 CFR Part 50, Appendix J." As stated by the applicant, this program is a containment leak rate monitoring program that follows Option B of 10 CFR Part 50, Appendix J, for integrated and local leak rate tests of components that make up the primary containment pressure boundary. The applicant stated that the program includes Types A, B, and C testing as described in 10 CFR Part 50, Appendix J, and provides for periodic verification of the leak
| |
| -tight integrity of the primary reactor containment. The applicant also stated that the Seabrook Station Leakage Test Reference is based on guidance provided in NEI 94
| |
| -01, "Industry Guideline for Implementing Performance
| |
| -Based Option of 10 CFR Part 50, Appendix J," and American National Standards Institute/American Nuclear Society (ANSI/ANS)
| |
| -56.8-1994, "Containment System Leakage Testing Requirements," with the restrictions identified in Regulatory Guide (RG) 1.163, "Performance
| |
| -Based Containment Leak
| |
| -Test Program." The applicant further stated that its 10 CFR Part 50, Appendix J Program, in conjunction with its ASME Code Section XI, Subsection IWE and IWL programs, provides an AMP that is effective at detecting degradation of the containment pressure boundary.
| |
| The applicant revised LRA Section B.2.1.30 program description by letter dated November 17, 2011 (ADAMS Accession No. ML11327A009), to indicate that the program manages the effects of aging related to containment pressure boundary deterioration and leak tightness together with its ASME Code Section XI, Subsection IWE (LRA Section B.2.1.27), and ASME Code Section XI, Subsection IWL (LRA Section B.2.1.28), programs. By letter dated October 6, 2017, the applicant amended LRA Section B.2.1.30 (ADAMS Accession No. ML17278A955), presented and evaluated below by the staff as "2017 Update to LRA AMP B.2.1.30," to indicate a change to 10 CFR Part 50, Appendix J, implementing documents.
| |
| Staff Evaluation. The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.S4. As discussed in the AMP audit report, the staff confirmed that each element of the applicant's program is consistent with the corresponding element of GALL Report AMP XI.S4, with the exception of the "detection of aging effects" program element. For this element, the staff determined the need for additional clarification, which resulted in the issuance of RAIs. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine whether they are bounded by the conditions for which the GALL Report was evaluated.
| |
| GALL Report AMP XI.S4 recommends a containment leak rate testing program as an effective method for detecting degradation of containment shells, liners, welds, and other components that comprise the containment pressure boundary, including seals and gaskets. It also states that this would be achieved with the additional implementation of an acceptable containment ISI program as described in GALL Report AMPs XI.S1 and XI.S2. In addition, GALL Report AMP Aging Management Review Results 3-44 XI.S4 recommends a general inspection of internal and external surfaces of the containment prior to a Type A test. During its audit, the staff found that the applicant inspected containment surfaces prior to the most recent Type A test using its "complex procedure" for reactor containment integrated leakage rate testing (ILRT) and noted that the applicant's procedure does not specify examination methods for conducting internal and external inspections that are consistent with ASME Code Section XI, Subsections IWE and IWL, requirements.
| |
| By letter dated December 14, 2010, the staff issued RAI B.2.1.30
| |
| -1 (ADAMS Accession No. ML103420273), requesting that the applicant:
| |
| (1) Describe the methods and procedures used to conduct a general inspection of internal and external surfaces of the containment prior to the most recent Type A test.
| |
| (2) Indicate whether these methods and procedures are consistent with the containment ISI programs described in GALL Report AMPs XI.S1 and XI.S2.
| |
| (3) Describe the method being used to ensure that internal and external containment inspections are being implemented as described in GALL Report AMPs XI.S1 and XI.S2 and consistent with program element 4, "Detection of Aging Effects," of GALL Report AMP XI.S4.
| |
| In its response to RAI B.2.1.30
| |
| -1, item 1, dated January 13, 2011 (ADAMS Accession No. ML110140587), the applicant stated that the Type A test conducted in 2008 was performed using the "'Reactor Containment Integrated Leakage Rate Test
| |
| - Type A' complex procedure." As stated by the applicant, this "procedure contains a prerequisite which states '[a] general inspection of the accessible interior and exterior surfaces of the containment structure and components is complete.'" In addition, the applicant stated:
| |
| The inspection requires that: "The structural integrity shall be determined by a visual inspection of the exposed accessible interior and exterior surfaces of the containment vessel. The inspection shall be performed to verify no apparent changes in appearance of the surfaces or other abnormal degradation. Any abnormal degradation of the containment vessel detected during the above required inspections shall be reported to the Commission in a Special Report pursuant to T.S. 6.8.2 within 15 days."
| |
| The general inspection of the accessible interior and exterior surfaces of the containment structure is a requirement from 10 CFR Part 50, Appendix J, Subsection V.A, and is in addition to, and totally separate from, the inspection requirements of ASME Code Section XI, Subsections IWE and IWL.
| |
| In response to RAI B.2.1.30
| |
| -1, item 2, the applicant stated that the Seabrook Appendix J Program is consistent with the requirements of GALL Report AMP XI.S4 and that the containment inspection required by 10 CFR Part 50, Appendix J, is in addition to and separate from the recommendations of GALL Report AMP XI.SI and XI.S2.
| |
| In response to item 3, the applicant stated that its ASME Code Section XI, Subsections IWE and IWL programs, are consistent with GALL Report AMPs XI.S1 and XI.S2, and that the inspections conducted as part of its 10 CFR Part 50, Appendix J Program, are consistent with GALL Report AMP XI.S4.
| |
| | |
| Aging Management Review Results 3-45 The staff finds the applicant's response to RAI B.2.1.30
| |
| -1 acceptable because containment structural deteriorations and leak tightness are evaluated and assessed prior to and between Type A tests based on the required 10 CFR Part 50, Appendix J, general visual examinations and 10 CFR 50.55a ASME Code Section XI, IWE and IWL, visual inspections, subject to GALL Report AMPs XI.S1 and XI.S2 added guidance. The staff's concerns in RAI B.2.1.30
| |
| -1 are resolved.
| |
| During the audit of program element 4, "detection of aging effects," the staff also reviewed the "complex procedure" for reactor containment ILRT and qualification guidance for personnel who conducted visual examinations of concrete containment surfaces. The staff concluded that the qualification of personnel who conduct visual examinations of concrete containment surfaces should be consistent with qualification provisions in IWA
| |
| -2300 as required by 10 CFR 50.55a. To this end, by letter dated December 14, 2010, the staff issued RAI B.2.1.30
| |
| -2, requesting the applicant to provide plans and a schedule to: (i) ensure that personnel who perform visual examinations of concrete containment surfaces are in compliance with Option B for ILRTs and are qualified in accordance with IWA
| |
| -2300 requirements, and (ii) verify that the applicant's 10 CFR Part 50, Appendix J, AMP is consistent with GALL Report AMP XI.S4, "10 CFR Part 50, Appendix J."
| |
| In its response dated January 13, 2011, the applicant stated:
| |
| Personnel performing the visual examinations of concrete surfaces prior to Integrated Leak Rate Test are not qualified in accordance with IWA
| |
| -2300. There is no requirement in 10 CFR 50.55a that Appendix J general visual inspection personnel be qualified per IWA
| |
| -2300. This is a general inspection of the containment surface for any apparent degradation that would cause failure of the Integrated Leak Rate Test. Since there are no requirements for inspector qualifications, the Appendix J aging management program is consistent with GALL Report AMP XI.S4, "10 CFR Part 50, Appendix J." Personnel performing the visual examinations required by the ASME Code Section XI Subsections IWE and IWL are qualified to the requirements of IWA
| |
| -2300. The staff reviewed the applicant's response to RAI B.2.1.30
| |
| -2 and noted that its "complex procedure" and "Containment and Containment Enclosure Surface Inspection" procedure did not reveal any information about the qualification of the personnel performing visual examinations. In addition, the staff noted the applicant's response did not provide any specific quantitative acceptance criteria that would define severe cracks, spalling, popouts, surface voids, or other irregularities, of the containment interior and exterior surfaces. The staff also noted that the lack of qualification requirements for personnel performing general visual examinations may affect the structural integrity and leak tightness of the concrete containment during the period of extended operation. By letter dated November 3, 2011 (ADAMS Accession No. ML11304A001), the staff issued a followup RAI B.2.1.30
| |
| -2 requesting additional information on the qualifications of personnel performing general visual inspections of the accessible interior and exterior surfaces of the containment system prior to each Type A test and at a periodic interval between Type A tests for assessment of structural deterioration that could affect containment leak
| |
| -tight integrity. In addition, the staff requested that the applicant provide the acceptance criteria used for these inspections.
| |
| In its response to followup RAI B.2.1.30
| |
| -2, by letter dated November 17, 2011 (ADAMS Accession No. ML11327A009), the applicant stated:
| |
| | |
| Aging Management Review Results 3-46 [The] Containment Inservice Inspection Program was developed for Seabrook Station Class MC and CC components in accordance with the requirements of ASME Code, Section XI, Subsections IWA, IWE and IWL [-] [and] examinations are accomplished utilizing methods such as general and detailed visual examinations, and volumetric examinations.
| |
| - Personnel performing the Type A pretest general visual inspection utilize the Containment and Containment Enclosure Surface Inspection procedure, and are qualified to the Qualification Guide, Engineering Support Personnel Training Program for Appendix J Engineer. The procedure provides qualitative criteria needed to detect structural problems that may affect either the containment structure leakage integrity or the performance of the Type A test.
| |
| The applicant also initiated a change to this procedure to clarify the current inspection practices as follows:
| |
| During refueling outages when Subsection IWE inspections and the ILRT are to be performed, both the IWE and Appendix J examinations will be performed prior to the ILRT. The Appendix J Engineer will review the results of the most recent Subsection IWL inspections as well as any issues identified from the IWE inspections prior to conducting the Appendix J general visual inspection.
| |
| During refueling outages when a Subsection IWE inspection is not performed, and the Appendix J general visual inspection is required, the Appendix J Engineer will review the results of the most recent Subsection IWE and IWL inspections and then perform a separate general visual inspection in accordance with the Containment and Containment Enclosure Surface Inspection procedure.
| |
| The applicant also stated that its 10 CFR Part 50, Appendix J, and its ASME Code
| |
| -based IWE and IWL programs are three distinct programs that together "provide an aging management program that is effective at detecting degradation of the containment boundary," as noted in the revision of the program description dated November 17, 2011.
| |
| The staff finds the applicant's response to followup RAI B.2.30
| |
| -2 acceptable because the personnel performing the visual examination of the containment for 10 CFR Part 50, Appendix J, Type A test program are qualified to identify structural deterioration that could challenge the leak tightness and structural integrity of the containment and containment enclosure building, and because such required visual inspections are further augmented with the mandated ASME Code Section XI, Subsections IWE and IWL Program, examinations. The staff's concerns in RAI B.2.1.30
| |
| -2 and followup RAI B.2.30
| |
| -2 are resolved.
| |
| 2017 Update to LRA AMP B.2.1.30. By letter dated October 6, 2017, the applicant submitted LRA supplement 57 (ADAMS Accession No. ML17278A955), revising portions of LRA Section B.2.1.30, "10 CFR Part 50, Appendix J," program description, which states that, consistent with the plant's technical specification (TS) 6.15, "Containment Leak Rate Program," the current implementing documents for 10 CFR Part 50, Appendix J, Option B are:
| |
| | |
| Aging Management Review Results 3-47
| |
| * NEI 94-01, Revision 3
| |
| -A, "Industry Guideline for Implementing Performance
| |
| -Based Option of 10 CFR Part 50, Appendix J" and
| |
| * The conditions and limitations specified in NEI 94
| |
| -01, Revision 2
| |
| -A LRA Supplement 57 also states that the "Seabrook Station Leakage Test Reference is based on the guidance provided in NEI TR 94
| |
| -01, Revision 3
| |
| -A, and ANSI/ANS 56.8
| |
| -2002." The staff noted that documents used for regulatory implementation of 10 CFR Part 50, Appendix J, are inconsistent with those listed in "monitoring and trending" and "corrective actions" program elements of GALL Report, Revision 1, AMP XI.S4, with which the applicant claims consistency of its 10 CFR Part 50, Appendix J, AMP. Based on GALL Report, Revision 1 and SRP
| |
| -LR, Revision 1, guidance, the staff determined the need for additional information associated with these two program elements, which resulted in the issuance of RAI B.2.1.30
| |
| -3. On January 29, 2018 (ADAMS Accession No. ML18026A879), the staff requested that the applicant clarify why LRA AMP B.2.1.30 "monitoring and trending" and "corrective actions," program elements would still follow the initial issue of NEI 94
| |
| -01 (Revision 0), as endorsed by NRC RG 1.163, instead of those described in TS 6.15 and in Seabrook LRA Supplement 57.
| |
| By letter dated February 28, 2018, the applicant responded to RAI B.2.1.30
| |
| -3 via Seabrook LRA Supplement 59 (ADAMS Accession No. ML18059B203) and stated that "exceptions exist between [-] [its] 10 CFR Appendix J program," and the "monitoring and trending" and "corrective actions" program elements in GALL Report AMP XI.S4. As part of its response, the applicant also included a revised program description as well as exceptions to the "monitoring and trending" and "corrective actions" program elements. The staff finds the applicant's response acceptable because the exceptions taken address the discrepancy between its 10 CFR Part 50, Appendix J, AMP and the GALL Report, Revision 1, XI.S4 AMP. The staff's concerns in RAI B.2.1.30
| |
| -3 are resolved.
| |
| The staff's evaluation of exceptions to the two aforementioned program elements follows:
| |
| Exception 1. LRA Section B.2.1.30, as revised by letter dated February 28, 2018, includes an exception to the "monitoring and trending" program element. The staff reviewed this exception against the corresponding program element in GALL Report AMP XI.S4 and finds it acceptable because the applicant adopts NEI 94
| |
| -01, Revision 3
| |
| -A, as the implementing document to meet the regulatory requirements for 10 CFR Part 50 Appendix J, Option B (performance
| |
| -based), as reviewed and approved by the NRC staff in its issuance of Amendment No. 153 to Seabrook Facility Operating License No. NPF
| |
| -86 (ADAMS Accession No. ML17046A443). The staffapproved revision to the TS (Amendment No. 153) allows the applicant to change the performance
| |
| -based test intervals for Type A tests (ILRTs) up to one test in 15 years and extends the Type C tests (LLRTs) interval up to 75 months, based on their acceptable performance history as defined in NEI 94
| |
| -01, Revision 3
| |
| -A. Exception 2. LRA Section B.2.1.30, as revised by letter dated February 28, 2018, includes an exception to the "corrective actions," program element. The staff reviewed this exception against the corresponding program elements in GALL Report AMP XI.S4 and finds it acceptable because Seabrook applies the provisions for corrective actions in accordance with NEI 94-01, Revision 3
| |
| -A, which is the staff
| |
| -approved implementing document for the 10 CFR Part 50, Appendix J, regulatory requirements, as noted in Exception 1 above.
| |
| | |
| Aging Management Review Results 3-48 Based on its AMP audit and review of the applicant's responses to RAI B.2.1.30-1, RAI B.2.1.30
| |
| -2, RAI Followup B.2.1.30
| |
| -2, and RAI B.2.1.30
| |
| -3, the staff finds that elements one through six of the 10 CFR Part 50, Appendix J AMP, with acceptable exceptions, are consistent with the corresponding program elements of GALL Report AMP XI.S4 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.30 summarizes operating experience related to the 10 CFR Part 50, Appendix J AMP. The applicant indicated that implementation of Option B for leakage testing frequency is consistent with plant operating experience and also described results of Types B and C local leak rate tests performed during RFOs 9, 10, 11, and 12. Although these tests identified leakage from various isolation valves and containment on
| |
| -line purge penetrations that required repair or replacement, the applicant stated that no major issues were found and that all as
| |
| -left local leak rate test results for RFOs 9, 10, 11, and 12 were acceptable. During the audit, the staff found that the most recent Type A test was completed in 2008 and that the results of this test were within acceptable limits.
| |
| The staff reviewed operating experience information in the application and during the audit to determine whether the applicable aging effects and industry and plant-specific operating experience were reviewed by the applicant. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine whether the applicant had adequately incorporated and evaluated operating experience related to this program.
| |
| During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation. Based on its audit and review of the application, the staff finds that the applicant has appropriately evaluated plant
| |
| -specific and industry operating experience related to its program. The operating experience demonstrates that the program can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking appropriate corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10 and, therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program as described in SRP
| |
| -LR Table 3.5
| |
| -2. The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). LRA Section A.2.1.30 provides the UFSAR supplement for the 10 CFR Part 50, Appendix J AMP.
| |
| Conclusion. On the basis of its audit and review of the applicant's 10 CFR Part 50, Appendix J Program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exceptions and their justification and determined that the AMP, with exceptions, is adequate to manage the aging effects for which the LRA credits them. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP Aging Management Review Results 3-49 and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.1.12 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program Summary of Technical Information in the Application. LRA Section B.2.1.32 describes the new Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification (EQ) Requirements Program as consistent with GALL Report AMP XI.E1, "Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements." The applicant stated that the Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Program will manage the aging effects of embrittlement, cracking, discoloration, or surface contamination leading to reduced insulation resistance or electrical failure of accessible cables and connections due to exposure to an adverse localized environment caused by heat, radiation, or moisture in the presence of oxygen. The applicant also stated that accessible electrical cables and connections exposed to adverse localize d environments or ambient conditions in excess of 60
| |
| -year service limiting environments will be visually inspected for signs of accelerated age
| |
| -related degradation.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.E1. As discussed in the AMP audit report, the staff confirmed that these elements are consistent with the corresponding elements of GALL Report AMP XI.E1.
| |
| Based on its audit and review of the application, the staff finds that elements one through six of the applicant's Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Program are consistent with the corresponding program elements of GALL Report AMP XI.E1 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.32 summarizes operating experience related to the new Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Program. The applicant claimed that both plant
| |
| -specific and industrywide operating experience was considered in the development of the program, and these considerations ensure that the program would be an effective AMP for the period of extended operation. The following particular observations were cited by the applicant, including the operating experience cited in NUREG-1801, Chapter XI, Section E1:
| |
| * the shared experiences of plant operators in the NEI License Renewal Working Group
| |
| * the results from Seabrook's corrective action program, in particular with respect to degraded cable insulation from localized areas of overheating
| |
| * Seabrook plant engineering guidelines for system walkdowns that prompt engineers to observe the condition of cable and connections
| |
| | |
| Aging Management Review Results 3-50 Furthermore, in a condition report, the applicant stated that a project was undertaken in 1998 and 1999 to reduce the infiltration of groundwater into plant buildings by injecting a hydrophobic material through to the outside of the building walls. The effort was only partially successful and was terminated when tritium contamination above background was found in groundwater leaking into the containment annulus. The applicant performed a root cause evaluation and installed dewatering points in three locations around the plant. The staff noted that no recent events of water intrusion in cable trays and tunnels were identified. The staff performed an inspection of the 26
| |
| -ft electrical tunnel cable tray room and observed no water on cable tray or cables. The staff reviewed operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program. Further, the staff performed a search of regulatory operating experience for the 10
| |
| -year period through April 2010. Databases were searched using various key word searches and then reviewed by the technical auditor staff.
| |
| During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.32 provides the UFSAR supplement for the Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Program. The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Table 3.6
| |
| -2. The staff also noted that the applicant committed (Commitment 34) to implementing the new Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Program prior to entering the period of extended operation for managing aging of applicable components.
| |
| The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its review of the applicant's Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| | |
| Aging Management Review Results 3-51 3.0.3.1.13 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Summary of Technical Information in the Application. LRA Section B.2.1.33 describes the new Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program as consistent with GALL Report AMP XI.E2, "Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits." The applicant stated that the Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program will manage the aging effects of reduced insulation resistance due to exposure to adverse localized environments caused by heat, radiation, or moisture in the presence of oxygen, causing increased leakage currents. The applicant also stated that this program applies to sensitive instrumentation cable and connection circuits with low
| |
| -level signals in the in-scope portions of the neutron flux monitoring cable in the nuclear instrumentation system. Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| During its review, the staff confirmed that high
| |
| -voltage low
| |
| -level radiation monitoring system cables that are usually in
| |
| -scope of GALL Report AMP XI.E2 are included in the EQ Program by reviewing EQ equipment data sheets. The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.E2. As discussed in the audit report, the staff confirmed that these elements are consistent with the corresponding elements of GALL Report AMP XI.E2. Based on its audit and review of the application, the staff finds that elements one through six of the applicant's Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program are consistent with the corresponding program elements of GALL Report AMP XI.E2 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.33 summarizes operating experience related to the Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program. In the LRA, the applicant stated that Seabrook considers plant-specific and industrywide operating experience. The applicant also stated that, in 2008, testing was performed on all in
| |
| -core neutron flux monitoring cables and connections. The test results documented a less
| |
| -than-expected insulation resistance reading between the inner and outer shield. The low insulation resistance reading was attributed to the connector design. The applicant further stated that the design issue was resolved, and retesting found the cable and connection to be acceptable.
| |
| The staff reviewed operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program. Further, the staff performed a search of regulatory operating experience for the 10
| |
| -year period through April 2010. Databases were searched using various key word searches and then reviewed by the technical auditor staff.
| |
| | |
| Aging Management Review Results 3-52 During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effect s of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.33 provides the UFSAR supplement for the Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program. The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Table 3.6
| |
| -2. The staff also noted that the applicant committed (Commitment 35) to implement the new Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program prior to entering the period of extended operation for managing aging of applicable components.
| |
| The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its review of the applicant's Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.1.14 Metal Enclosed Bus Program Summary of Technical Information in the Application. LRA Section B.2.1.35 describes the new Metal Enclosed Bus (MEB) Program as consistent with GALL Report AMP XI.E4, "Metal Enclosed Bus." The applicant stated that the MEB Program is a new program that will manage the following aging effects of in
| |
| -scope MEBs:
| |
| * loosening of bolted connections due to thermal cycling and ohmic heating
| |
| * hardening and loss of strength due to elastomer degradation
| |
| * loss of material due to general corrosion
| |
| * embrittlement, cracking, melting, swelling, or discoloration due to overheating or aging degradation The applicant further stated that this new program will be implemented prior to entering the period of extended operation and inspection will be conducted at least once every 10 years Aging Management Review Results 3-53 after the period of extended operation. Aging management of the exterior housing and elastomers of the in
| |
| -scope MEBs is included in the Structures Monitoring Program.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.E4. As discussed in the AMP audit report, the staff confirmed that each element of the applicant's program is consistent with the corresponding element of GALL Report AMP XI.E4, with the exception of the "detection of aging effects" program element. For this element, the staff determined the need for additional clarification, which resulted in the issuance of an RAI.
| |
| In the Seabrook basis document LRAP
| |
| -E4, under the "detection of aging effect" element, the applicant states that the MEB Program will perform thermography inspections external to the MEBs to determine if the in
| |
| -scope MEBs have loose connections due to thermal cycling and ohmic heating. The inspections will be performed on all accessible bus sections while the bus is energized. Normally, windows are installed on the MEB to facilitate these thermography inspections. The metal
| |
| -enclosed cover may mask the heat created by loosening of bus connections, and the temperature differences between bus connections may not be detected if windows are not installed on MEBs. During the LRA onsite audit in the week of October 21, 2010, the staff asked the applicant to clarify how the MEB connection inspections at Seabrook are effective in detecting loosening of bus connections using external thermography measurements. In a letter dated November 15, 2010, the applicant revised the MEB Program description to clarify that, if thermography is used to identify loose connections, the applicant will use inspection techniques that will provide accurate readings. In addition, the applicant added connection resistance measurements as an alternate method to determine if MEB connections are loose. The applicant revised LRA Appendix B, Section B.2.1.35 as follows: The internal portions of the in
| |
| -scope metal enclosed bus enclosures will be visually inspected for aging degradation of insulating material and for cracks, corrosion, foreign debris, excessive bust buildup, and evidence of moisture intrusion. The bus insulation will be visually inspected for signs of embrittlement, cracking, melting, swelling, or discoloration, which may indicate overheating or aging degradation. The isolated phase bus conductor is not insulated. The internal bus supports will be visually inspected for structural integrity and signs of cracks. The accessible bus section will be inspected for loose connections using a thermography inspection technique that will provide accurate temperature readings of the bus bolted connection temperatures, such as through view ports. As an alternative to thermography, connection resistance measurements may be used to determine if the in
| |
| -scope MEBs have loose connections due to thermal cycling and ohmic heating. The program requires that bolted connections be below the maximum allowed temperature for the application, and free of unacceptable visual defects. The staff finds the applicant's supplement to LRA Section B.2.1.35 acceptable because it will be performing thermography (such as through view ports) that will provide accurate temperature readings of the bus bolted connections temperature compared to using thermography external Aging Management Review Results 3-54 to the MEB metal
| |
| -enclosed cover. The staff also finds that the connection resistance measurement, as an alternative to thermography, is acceptable to determine if the bus connections are loosening due to thermal cycling and ohmic heating because high resistance measurement will indicate that the bus connections are loosening. The inspection technique (thermography or resistance measurements) is consistent with that in GALL Report AMP XI.E4.
| |
| Based on its audit and review of the application and the applicant's response in a letter dated November 15, 2010, the staff finds that elements one through six of the applicant's MEB Program are consistent with the corresponding program elements of GALL Report AMP XI.E4 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.35 summarizes operating experience related to the MEB Program. The applicant stated that plant
| |
| -specific and industrywide operating experience was considered in the development of this program. The applicant also stated that the Institute of Nuclear Plant Operation (INPO) issued a Special Event Report, SER 5
| |
| -09, "6.9-kV Non-segregated Bus Failure and Complicated Scram." The event report documents the catastrophic failure of a 6.9
| |
| -kV non-segregated bus. The cause of the event was attributed to the overheating of the center bus bar at the flex connection. Seabrook performs periodic visual inspections and infrared thermography tests on all in
| |
| -scope non-segregated buses and the isolated phase buses. In 2005, during the inspection of a non
| |
| -segregated phase bus, white corrosion was found on a bolted connection surface near a flat washer. In addition, a green residue was noted on the surface area of the bus near the connection area. The applicant also stated that the connection was broken to facilitate a complete inspection of the connection for additional corrosion. The connection was remade and successfully tested. The same duct was also noted to have an expansion joint that was not sealing. The applicant corrected the deficiency.
| |
| The staff reviewed the operating experience, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program. Further, the staff performed a search of regulatory operating experience for the 10
| |
| -year period through March 2010. Databases were searched using various key word searches and then reviewed by the technical auditor staff.
| |
| During its review, the staff found no additional operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that the program can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.35 provides the UFSAR supplement for the MEB Program. The staff reviewed this UFSAR supplement description of the program and noted that Aging Management Review Results 3-55 it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Table 3.6-2. The staff also noted that the applicant committed (Commitment 37) to implementing the new MEB Program inspections once every 10 years, with the first inspection to be performed prior to entering the period of extended operation, in order to manage aging of applicable components.
| |
| The staff determined that the information in the UFSAR supplement, as amended, is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its audit and review of the applicant's MEB Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.1.15 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program Summary of Technical Information in the Application. LRA Section B.2.1.37 describes the new Electrical Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements Program as consistent with GALL Report AMP XI.E6, "Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements," as modified by LR
| |
| -ISG-2007-02. The applicant stated that the Electrical Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements Program is a new, one
| |
| -time testing program that will be used to verify that the aging effect of loosened bolted connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation on the metallic portion of electrical cable connections does not require management. The applicant further stated that a representative sample of cable connections within the scope of license renewal will be selected for one
| |
| -time testing prior to the period of extended operation.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of the GALL Report AMP XI.E6. As discussed in the AMP audit report, the staff confirmed that each element of the applicant's program is consistent with the corresponding element of the GALL Report AMP XI.E6, with the exception of the "parameters monitored or inspected" program element. For this element, the staff determined that additional clarification was required.
| |
| GALL Report AMP XI.E6, under the "parameters monitored or inspected" program element, states that a representative sample of electrical cable connections is tested. The technical basis for the sample selected is to be documented. The implementing document for the program will provide the technical basis for the sample selection with respect to both sample size and inspection locations. In the basis document, LRAP
| |
| -E6, under the same program element, the Seabrook program performs tests on a representative sample of electrical cable Aging Management Review Results 3-56 connections. The monitoring includes loosening of bolted connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation. The applicant developed the technical basis for selecting samples of cable connections and documented it as Technical Report, LRTR
| |
| -E6, "Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Sample Selection," Revision 1.
| |
| During the audit, the staff found that the sample size was not included in LRTR
| |
| -E6, Revision 1. During the break
| |
| -out meeting, the staff discussed with the applicant its concerns that the sample size is not being included in the technical report. The applicant revised the technical report (LRTR
| |
| -E6, Revision 2) to include the sample size such that the sample set shall include at least 20 percent of the connections for each category listed below or a minimum of 25 connections of each of the following categories:
| |
| * power (4.160 kV and 13.8 kV) crimped/bolted
| |
| * power (460 V and 480 V) crimped/bolted
| |
| * control (120 VAC [volts
| |
| -alternating current] and 125 VDC [volts
| |
| -direct current]) crimped/terminal board connection
| |
| * instrument (low voltage) crimped/terminal board connection The staff reviewed the technical report revision and found that the sample size is consistent with current staff positions.
| |
| Based on its audit, and review of LRA Section B.2.1.37 and LRTR
| |
| -E6, Revision 2, the staff finds that elements one through six of the applicant's Electrical Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements Program are consistent with the corresponding program elements of GALL Report AMP XI.E6, as modified by final LR
| |
| -ISG-2007-02 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.37 summarizes operating experience related to the Electrical Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements Program. Although a new program, the applicant stated that plant
| |
| -specific operating experience and industrywide operating experience were considered in the development of this program. The applicant further stated that a review of plant
| |
| -specific and industrywide operating experience ensures that the one
| |
| -time inspection corresponding to GALL Report AMP XI.E6 will confirm the absence or presence of age
| |
| -related degradation of cable connections caused by thermal cycling, ohmic heating, corrosion, and oxidation. The applicant stated that Seabrook routinely performs infrared thermography tests on numerous pieces of equipment, including electrical connections, as part of the Preventive Maintenance Program. In 2002, during an infrared thermography inspection of a 480
| |
| -volt circuit breaker, a hot connection was found. The connection was approximately 150 °F hotter than similar connections. Seabrook procedures required that the connection be corrected within 1 week. Infrared thermography was used to monitor the connection on a daily basis until corrective action could be taken. The applicant further stated that, in 2005, an infrared thermography inspection identified heating on three connections in a control panel. The connections were 30
| |
| -50 °F higher than expected. Seabrook procedures require that this condition be corrected in 12 weeks. The hot connections were repaired. The connections were found to be tight, and the hot spot was attributed to defective connectors.
| |
| | |
| Aging Management Review Results 3-57 The staff reviewed operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant and are evaluated in accordance with the GALL Report. As discussed in the audit report, the staff conducted walkdowns, interviewed the applicant's staff, and reviewed onsite documentation provided by the applicant. The staff also conducted an independent search of the applicant's operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program.
| |
| Further, the staff performed a search of regulatory operating experience for the period 2000 through April 2010. Databases were searched using various key word searches and then reviewed by the technical auditor staff.
| |
| During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.37 provides the UFSAR supplement for the Electrical Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements Program.
| |
| The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Table 3.6-2, as modified by the applicant's implementation of LR
| |
| -ISG-2007-02. The staff also noted that the applicant committed (Commitment 39) to implementing the new Electrical Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements Program prior to entering the period of extended operation for managing aging of applicable components.
| |
| The staff determined that the information in the UFSAR supplement, as amended, is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its audit and review of the applicant's Electrical Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements Program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent with the GALL Report and LR
| |
| -ISG-2007-02. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.1.16 Environmental Qualification of Electric Components Program
| |
| | |
| Aging Management Review Results 3-58 Summary of Technical Information in the Application. LRA Section B.2.3.2 describes the existing EQ of Electric Components Program as consistent with GALL Report AMP X.E1, "Environmental Qualification (EQ) of Electric Components." The applicant also stated that the EQ Program manages component thermal, radiation, and cyclic aging through the use of 10 CFR 50.49(f) qualification methods. The applicant also stated that qualified lives are determined for equipment within the scope of the EQ Program, and appropriate actions such as replacement, refurbishment, or reevaluation are taken prior to the end of the qualified life of the equipment so that the aging limit is not exceeded. The applicant further stated that all EQ equipment is included within the scope of license renewal.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated. As part of a power uprate to increase generating capacity by 5.2 percent and as part of license renewal, the applicant updated EQ calculations for EQ electrical equipment. The staff reviewed a sample of these calculations to ensure that the design change adequately accounted for the power uprate and the extended qualified life for license renewal.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP X.E1. As discussed in the AMP audit report, the staff confirmed that each element of the applicant's program is consistent with the corresponding element of GALL Report AMP X.E1. Based on its audit and review of the application, the staff finds that elements one through six of the applicant's EQ of Electric Components Program are consistent with the corresponding program elements of GALL Report AMP X.E1 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.3.2 summarizes operating experience related to the EQ of Electric Components Program. The applicant stated its program is an existing program and has been maintained by onsite engineering personnel since its inception. The applicant also stated that Seabrook has a comprehensive operating experience program that monitors industry issues/events and assesses these for applicability to its own operations.
| |
| The applicant listed samples of condition reports in LRA Section B.2.3.2 such as those listed below:
| |
| * reducing solenoid qualified lives based on temperature monitoring
| |
| * potential loss of the environmental seal due to the twisting of a transmitter's electronics housing
| |
| * potentially different greases being used on EQ fan motor bearings The applicant stated the operating experience of the EQ Program did not show any adverse trend in performance. The applicant further stated the key elements of the EQ Program are being monitored and effectively implemented.
| |
| The staff reviewed the operating experience in the application and during the audit to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant and evaluated in the GALL Report. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related Aging Management Review Results 3-59 to this program. Further, the staff performed a search of regulatory operating experience for the 10-year period through April 2010. Databases were searched using various key word searches and then reviewed by the technical auditor staff.
| |
| During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.3.2 provides the UFSAR supplement for the EQ of Electric Components Program. The staff reviewed this UFSAR supplement description of the program and noted that, in conjunction with LRA Section 4.4, it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Tables 4.4
| |
| -1 and 4.4-2. The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its review of the applicant's EQ of Electric Components Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.2 Aging Management Programs Consistent with the GALL Report with Exceptions or Enhancements In LRA Appendix B, the applicant stated that the following AMPs are, or will be, consistent with the GALL Report, with exceptions or enhancements:
| |
| * Reactor Head Closure Studs Program
| |
| * Steam Generator Tube Integrity Program
| |
| * Open-Cycle Cooling Water System Program
| |
| * Closed-Cycle Cooling Water System Program
| |
| * Inspection of Overhead Heavy Load Handling Systems Program
| |
| * Compressed Air Monitoring Program
| |
| * Fire Protection Program
| |
| * Fire Water System Program
| |
| * Aboveground Steel Tank Program
| |
| | |
| Aging Management Review Results 3-60
| |
| * Fuel Oil Chemistry Program
| |
| * Reactor Vessel Surveillance Program
| |
| * Selective Leaching of Materials Program
| |
| * One-Time Inspection of ASME Code Class 1 Small
| |
| -Bore Piping Program
| |
| * External Surfaces Monitoring Program
| |
| * Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program
| |
| * Lubricating Oil Analysis Program
| |
| * ASME Code Section XI, Subsection IWL Program
| |
| * Structures Monitoring Program
| |
| * Inaccessible Power Cables Not Subject to 10 CFR 50.49 EQ Requirements Program
| |
| * Protective Coating Monitoring and Maintenance Program
| |
| * Metal Fatigue of Reactor Coolant Pressure Boundary Program For AMPs that the applicant claimed are consistent with the GALL Report, with exception(s) or enhancement(s) or both, the staff performed an audit and review to confirm that those attributes or features of the program, for which the applicant claimed consistency with the GALL Report, were indeed consistent. The staff also reviewed the exception(s) or enhancement(s) to the GALL Report to determine if they were acceptable and adequate. The results of the staff's audits and reviews are documented in the following sections.
| |
| 3.0.3.2.1 Reactor Head Closure Studs Program Summary of Technical Information in the Application. LRA Section B.2.1.3 describes the existing Reactor Head Closure Studs Program as consistent, with an exception, with GALL Report AMP XI.M3, "Reactor Head Closure Studs." The applicant stated that the aging effects of reactor vessel flange stud hole threads, reactor head closure studs, nuts, and washers are detected through visual or volumetric examination in accordance with the applicant's ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program, to manage cracking and loss of material. The applicant also stated that the program implements the guidance outlined in RG 1.65, "Materials and Inspections for Reactor Vessel Closure Studs," Revision 1, dated April 2010, for preventive measures including material selection, appropriate coatings, and lubricants. The applicant further stated that reactor head closure studs are manufactured from SA
| |
| -540, Class 3, Grade B24 material. The applicant stated that these reactor head closure studs are coated with an anti
| |
| -galling metallic coating (PlasmaBond), and a station-approved lubricant is used during installation and removal of the studs that does not contain molybdenum disulfide.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.M3. As discussed in the audit report, the staff confirmed that each element of the applicant's program is consistent with the corresponding element of GALL Aging Management Review Results 3-61 Report AMP XI.M3, with the exception of the "preventive actions" program element. For this element, the staff determined the need for additional clarification, which resulted in the issuance of RAIs. In its review, the staff noted that RG 1.65 was originally issued in 1973. The staff also noted that RG 1.65, Revision 1, was issued in April 2010 and includes using bolting material for closure studs that has a measured yield strength less than 150 ksi, which is resistant to stress corrosion cracking. The staff further noted that LRA Section B.2.1.3 states that the applicant's reactor head closure studs are manufactured from SA
| |
| -540, Class 3, Grade B24 material, and the maximum tensile strength of the material is less than 170 ksi, as recommended in the GALL Report and RG 1.65 issued in 1973. However, the staff noted that the applicant's program does not include the preventive action using stud materials with a measured yield strength level less than 150 ksi in comparison with RG 1.65, Revision 1. By letter dated December 14, 2010 (ADAMS Accession No. ML103260554), the staff issued RAI B.2.1.3
| |
| -1, requesting that the applicant (a) clarify whether the measured yield strength of the reactor head closure stud material exceeds 150 ksi and (b) clarify whether there are program provisions that would preclude use of materials with yield strength greater than 150 ksi. The staff also requested that, if the program does not include provisions that would preclude use of materials with yield strength greater than 150 ksi or if the reactor head closure stud material has a yield strength level greater than or equal to 150 ksi, the applicant justify why the Reactor Head Closure Studs Program is adequate to manage stress corrosion cracking in the high
| |
| -strength material.
| |
| In its response dated January 13, 2011 (ADAMS Accession No. ML110140809), the applicant committed (Commitment 53) to replacing the reactor head closure stud(s) manufactured from the bar that has a yield strength greater than 150 ksi with ones that do not exceed 150 ksi prior to the period of extended operation. The applicant also stated that the yield strength from the test coupon for one of the bars, from which the studs were manufactured, was measured at 151.75 ksi, which is slightly higher than 150 ksi. The applicant further stated that the studs, which have yield strength measured at 151.75 ksi, are presently in storage. In addition, the applicant stated that its Reactor Head Closure Studs Program is revised to implement the guidance outlined in RG 1.65, Revision 1, such that its program includes the preventive action using stud materials with a measured yield strength not exceeding 150 ksi.
| |
| Based on its review, the staff finds the applicant's response to RAI B.2.1.3
| |
| -1 acceptable for the following reasons:
| |
| * The applicant's Reactor Head Closure Studs Program is revised to implement the guidance of RG 1.65, Revision 1, for the use of material with yield strength not exceeding 150 ksi.
| |
| * The applicant committed (Commitment 53) to replacing the reactor head closure studs with yield strength greater than 150 ksi, which are presently in storage, with the ones that do not exceed 150 ksi measured yield strength, consistent with the guidance in RG 1.65, Revision 1.
| |
| * The applicant's inspection, in accordance with the ASME Code Section XI, is adequate to detect and manage cracking due to stress corrosion cracking of the studs.
| |
| The staff's concern described in RAI B.2.1.3
| |
| -1 is resolved.
| |
| | |
| Aging Management Review Results 3-62 The staff noted that the program description of GALL Report AMP XI.M3 states that the recommended program includes ISI to detect cracking, loss of material, and coolant leakage from reactor head closure studs. The staff also noted that the "preventive actions" program element of GALL Report AMP XI.M3 includes using manganese phosphate or other acceptable surface treatments and stable lubricants. LRA Section B.2.1.3 indicates that a station
| |
| -approved lubricant is used during the installation and removal of the studs that does not contain molybdenum disulfide. The staff noted that the applicant's operating experience indicates that discoloration was reported on some of the reactor head closure studs during RFO 8 in 2002, and the discoloration on the PlasmaBond coating was determined to be the lubricant used for stud removal and was not considered an indication of stud degradation. By letter dated December 14, 2010, the staff issued RAI B.2.1.3
| |
| -2 (ADAMS Accession No. ML103260554), requesting that the applicant clarify the root cause for the discoloration on the closure studs. The staff also requested that the applicant provide the service temperature range of the lubricant in comparison with the operating temperatures of the reactor head closure studs. The staff further requested that the applicant clarify whether the lubricant is stable at the operating temperatures and is compatible with the stud and vessel materials and with the surrounding environment.
| |
| In its response dated January 13, 2011 (ADAMS Accession No. ML110140809), the applicant stated that a condition report from 2002 identified slight surface rust and discoloration on the PlasmaBond metallic coating on the reactor head closure studs. The applicant also stated that the PlasmaBond vendor indicates that the discoloration was due to tarnishing of the silver in the metallic coating, that the rust was limited to a small area near the top of the threaded portion of the stud that threads into the reactor vessel flange, and that the slight coating of rust identified in 2002 appears to have come from the reactor vessel stud hole. The applicant stated that during RFOs when the reactor head closure studs are removed, the stud holes are cleaned to remove any particles or deposits that may have accumulated in the stud holes. The applicant also stated that the inspection of the studs revealed no thread damage, and the small amount of surface rust and discoloration on the PlasmaBond coating is not considered an aging effect that requires management during the period of extended operation. The applicant stated that the lubricant (WD
| |
| -40) applied on the studs has an operating temperature range from
| |
| -10 °F to 200 °F and the operating temperature of the reactor head closure studs is estimated to approach 500 °F. In addition, the applicant stated that, according to the manufacturer of the lubricant, when the lubricant is exposed to the reactor vessel metal temperature at operating condition, it would carbonize and any carbonized deposits would have no adverse effect on the PlasmaBond coating or reactor vessel stud or flange materials.
| |
| The staff noted that the applicant's lubricant is also used to clean the reactor head closure studs during RFOs and later to protect potential corrosion of the stud material. The staff further noted that the applicant claimed that its review of plant-specific operating experience indicates no adverse effect on the aging of reactor head closure stud or vessel flange materials. However, the staff finds the applicant's response unacceptable because the operating temperature range of the lubricant (-10 °F to 200 °F) is significantly lower than the operating temperature of the reactor head closure studs that is estimated by the applicant to approach 500 °F. Additionally, the lubricant carbonizes at the operating temperature of the closure studs and the carbonization by
| |
| -products may accumulate on the stud threads and cause bolting material degradations. The staff also noted that the applicant's use of the lubricant is not consistent with the guidance in RG 1.65, that lubricants for the stud bolting are permissible provided they are stable at operating temperatures of the reactor head closure stud bolting. In Aging Management Review Results 3-63 addition, the staff was concerned that the carbonization of the lubricant and accumulation of carbonization by
| |
| -products on the studs and flange threads degrade the lubrication process of the bolting such that the removal operation of the studs may cause sticking, galling, or thread damage of the reactor head closure bolting.
| |
| By letter dated February 24, 2011 (ADAMS Accession No. ML110260266), the staff issued followup RAI B.2.1.3
| |
| -2. The staff asked the applicant to justify why the use of the lubricant, the operating temperature of which is significantly lower than that of the reactor head closure studs, is consistent with the guidance in RG 1.65 and the GALL Report, which state that lubricants for the stud bolting are permissible provided they are stable at operating temperatures of the reactor head closure stud bolting. The staff also requested that the applicant justify the use of the lubricant, which has an operating temperature range from
| |
| -10 °F to 200 °F, on the reactor head closure studs, which has an operating temperature that is estimated to approach 500 °F. The staff further requested that, if a justification for the use of this lubricant cannot be provided, the applicant state the lubricant it will use that will remain stable at operating temperatures of the reactor head closure stud bolting. In addition, the staff requested that the applicant justify why the carbonization of the lubricant and accumulation of carbonization by
| |
| -products on the studs and flange threads do not cause sticking, galling, or thread damage of the studs and flange threads and, as part of the justification, clarify whether the applicant's operating experience is in agreement with the justification.
| |
| In its response dated March 22, 2011 (ADAMS Accession No. ML110830045), the applicant stated that the LRA and its response to RAI B.2.1.3
| |
| -2 incorrectly referred to WD
| |
| -40 as a "lubricant" when, in fact, its intended use is to clean the reactor head closure studs and stud holes and protect them against rust and corrosion that can form at ambient temperatures, specifically, during installation and removal of the studs. The applicant also stated that the WD
| |
| -40 product has been evaluated for use as an expendable product on external surfaces at its site with no restrictions. In addition, once the WD
| |
| -40 is elevated to normal operating temperature of approximately 500 °F, the carbonized deposits have no adverse effect on the PlasmaBond coating, reactor vessel stud, or flange materials. The applicant further stated that it has not experienced sticking, galling, or thread damage of the studs or flange threads due to carbonization by
| |
| -products associated with WD
| |
| -40. Based on its review, the staff finds the applicant's responses to RAIs B.2.1.3
| |
| -2 and followup B.2.1.3-2 acceptable for the following reasons:
| |
| * The applicant's inspection results did not indicate thread damage on the reactor head closure studs associated with the discoloration, which was a result of tarnishing from the silver in the PlasmaBond coating.
| |
| * Any particle or deposit that may have accumulated in the stud holes will be removed during RFOs, so the potential of contamination or material accumulation is minimized on the stud and flange thread surfaces.
| |
| * The applicant clarified that WD
| |
| -40 is only used to clean and protect the exposed areas of the studs and stud holes from corrosion that can form at ambient temperatures.
| |
| * The plant-specific operating experience indicates no occurrence of sticking, galling, or thread damage due to the use of WD
| |
| -40. The staff's concerns described in RAIs B.2.1.3
| |
| -2 and followup B.2.1.3
| |
| -2 are resolved.
| |
| | |
| Aging Management Review Results 3-64 The staff also reviewed the portions of the "detection of aging effects" program element associated with the exception to determine if the program will be adequate to manage the aging effects for which it is credited. The staff's evaluation of this exception follows.
| |
| Exception. LRA Section B.2.1.3 states an exception to the "detection of aging effects" program element. The LRA states that the reactor head closure studs are removed from the reactor vessel during each RFO, and its ISIs are performed with the studs removed and consist of a volumetric examination only as allowed by Code Case N
| |
| -307-3 and current version of the ASME Code Section XI.
| |
| The staff noted that the "detection of aging effects" program element of GALL Report AMP XI.M3 recommends surface and volumetric examinations for the reactor head closure studs when removed, which are based on the requirements in Table IWB
| |
| -2500-1 of the 1995 Edition through the 1996 addenda of ASME Code Section XI. The staff also noted that the applicant clarified that the later version of the ASME Code referenced by GALL Report AMP XI.M3 (ASME Code 2001 edition including the 2002 and 2003 addenda) has been updated to include the Code Case N
| |
| -307-3 allowance that the surface examination may be eliminated. In its review, the staff also noted that RG 1.65, Revision 1, issued in April 2010, indicates that the use of Code Case N
| |
| -307-3 was approved by RG 1.147, Revision 15, "Inservice Inspection Code Case Acceptability, ASME Section XI, Division 1," issued in October 2007. Based on its review, the staff finds this exception to the "detection of aging effects" program element acceptable because the applicant performs volumetric examination of reactor head closure studs consistent with RG 1.65, Revision 1, and the 2001 edition of the ASME Code Section XI, including the 2002 and 2003 addenda. Additionally, the inspection, in accordance with the ASME Code Section XI requirements, is adequate to detect and manage loss of material due to wear and cracking due to stress corrosion cracking.
| |
| Based on its audit and review of the application and the applicant's response to RAIs B.2.1.3
| |
| -1, B.2.1.3-2, and followup B.2.1.3
| |
| -2, the staff finds that elements one through six of the applicant's Reactor Head Closure Studs Program, with an acceptable exception, are consistent with the corresponding program elements of GALL Report AMP XI.M3 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.3 summarizes operating experience related to the Reactor Head Closure Studs Program. The applicant stated that one reactor head closure stud was stuck due to galling during RFO 5 in 1997. The applicant also stated that the stud was cut out and appropriate repairs and retests were performed per the requirements of ASME Code Section XI. The applicant further stated that this operating experience prompted an investigation into suitable anti
| |
| -galling compounds, which resulted in the application of an anti
| |
| -galling metallic coating on the reactor head closure studs.
| |
| The applicant's operating experience also addressed the final post
| |
| -tensioned elongation values of reactor head studs. The applicant stated that one reactor head closure stud was found out of specified elongation range by 0.002 in. during RFO 10 in 2005. The applicant also stated that an engineering evaluation was performed and that the preload induced by post
| |
| -tensioning was below the designed range but was adequate to carry the reactor vessel pressure design loads. During the audit, the applicant further stated that the out
| |
| -o f-specification condition was a one
| |
| -time operational occurrence and was not associated with aging of reactor head closure studs.
| |
| | |
| Aging Management Review Results 3-65 The staff reviewed operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program. During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.3 provides the UFSAR supplement for the Reactor Head Closure Studs Program. The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Table 3.1
| |
| -2. The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its audit and review of the applicant's Reactor Head Closure Studs Program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and its justification and determined that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.2.2 Steam Generator Tube Integrity Program Summary of Technical Information in the Application. LRA Section B.2.1.10 originally described the Steam Generator Tube Integrity Program as consistent, with exceptions, with GALL Report AMP XI.M19, "Steam Generator Tube Integrity." The applicant amended this LRA section by letter dated June 19, 2015 (LRA Supplement No. 25), to indicate that the program is based on Revision 3 of NEI 97
| |
| -06, "Steam Generator Program Guidelines," in accordance with License Renewal Interim Staff Guidance (LR
| |
| -ISG) 2011-02, "Aging Management Program for Steam Generators," and letter dated May 25, 2017 (LRA Supplement No. 53), to indicate that the program is in accordance with LR
| |
| -ISG-2016-01, "Changes to Aging Management Guidance for Various Steam Generator Components." The revised LRA Section B.2.1.10 now describes the Steam Generator Tube Integrity Program as consistent with GALL Report AMP XI.M19, "Steam Generator Tube Integrity."
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| | |
| Aging Management Review Results 3-66 The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.M19. As discussed in the audit report, the staff confirmed that these elements are consistent with the corresponding elements of GAL L Report AMP XI.M19.
| |
| The staff also reviewed the portions of the "scope of program" program element associated with the exception to determine whether the program will be adequate to manage the aging effects for which it is credited. The staff's evaluation of this exception follows.
| |
| Exception 1. LRA Section B.2.1.10 states an exception to the "scope of program" program element. The GALL Report recommends that the applicant implement the steam generator (SG) degradation management program described in NEI 97-06, "Steam Generator Program Guidelines," Revision 1, to manage effects of aging on the SG tubes, plugs, sleeves, and tube supports. Alternatively, this program element states that the Steam Generator Tube Integrity Program is based on NEI 97
| |
| -06, Revision 2. The applicant stated that Revision 2 of NEI 97
| |
| -06 does not reduce the functional requirements of Revision 1. In addition, the applicant stated that NEI determined that Revision 2 is consistent with Technical Specification Task Force (TSTF)-449, Revision 4, "Steam Generator Tube Integrity." The applicant stated that Seabrook implemented TSTF
| |
| -449 with License Amendment No. 115 to the technical specifications in June 2007. The staff notes that Seabrook implemented TSTF
| |
| -510, "Revision to Steam Generator Program Inspection Frequencies and Tube Sample Selection" in October 2013, with License Amendment No. 138 to the technical specifications. The staff reviewed this exception and the guidance document NEI 97
| |
| -06, Revision 1, recommended by the GALL Report AMP. The staff has reviewed NEI 97
| |
| -06, Revision 2, and has found the guidance document consistent with the GALL Report because it does not reduce the fundamental requirements found in Revision 1. In addition, Revision 2 contains updated operating experience relevant to ensure that tube integrity is maintained.
| |
| The staff finds this program exception acceptable and consistent with the one described in the GALL Report Section XI.M19 because NEI 97
| |
| -06, Revision 2, does not reduce the fundamental requirements of Revision 1, which is recommended by the GALL Report AMP, and Revision 2 was determined to be acceptable since it is consistent with TSTF
| |
| -449. Based on its audit and review of the application, the staff finds that elements one through six of the applicant's Steam Generator Tube Integrity Program, with an acceptable exception, are consistent with the corresponding program elements of GALL Report AMP XI.M19 and, therefore, are acceptable.
| |
| In its letter dated June 19, 2015 (LRA Supplement No. 25), the applicant revised LRA B.2.1.10 to indicate that the program is based on Revision 3 of NEI 97
| |
| -06 in accordance with LR-ISG 2011-02, "Aging Management Program for Steam Generators." The staff's evaluation of this revision is discussed below.
| |
| By letter dated June 19, 2015, the applicant revised LRA Section B.2.1.10. In this revision, the applicant indicated that the LR
| |
| -ISG-2011-02 recommends that a license renewal applicant follow the guidance provided in NEI 97
| |
| -06, Revision 3, when implementing its steam generator AMP. The applicant also indicated that LR
| |
| -ISG-2011-02 recommends the use of Revision 3 of EPRI Steam Generator Integrity Assessment Guidelines (EPRI Report 1019038) for aging management of steam generators. The applicant accordingly revised LRA Section Aging Management Review Results 3-67 B.2.1.10 to clarify that the Steam Generator Tube Integrity Program is consistent with NEI 97
| |
| -06, Revision 3, in accordance with LR
| |
| -ISG-2011-02. The staff noted that the major change made in Revision 3 of NEI 97
| |
| -06 from Revision 2 was removal of program "requirements" in NEI 97
| |
| -06 as they are now incorporated in EPRI steam generator management guideline documents that are referenced in NEI 97-06. The staff also noted that Revision 3 of NEI 97
| |
| -06 includes updated definitions and other editorial changes that ensure consistency between NEI 97
| |
| -06 and technical specifications for steam generators. In addition, LR
| |
| -ISG-2011-02 identifies the updated revision, Revision 3, of EPRI Steam Generator Integrity Assessment Guidelines (EPRI Report 1019038) instead of Revision 2 of the guidelines (EPRI Report 1012987) that was incorrectly referenced in Section XI.M9 of GALL Report, Revision 2.
| |
| As discussed above, the staff finds that the applicant's revision to LRA Section B.2.1.10 is acceptable because it confirms that the Steam Generator Tube Integrity Program is consistent with NEI 97
| |
| -06, Revision 3, in accordance with LR
| |
| -ISG-2011-02. The staff also finds that the previously identified Exception 1 is no longer a program exception because the applicant's program is consistent with the guidance in LR
| |
| -ISG-2011-02 (i.e., the program is consistent with the GALL Report as modified by LR
| |
| -ISG-2011-02). By letter dated May 25, 2017, the applicant again revised LRA Section B.2.1.10. In this revision, the applicant indicated that LR
| |
| -ISG-2016-01 recommends changes to aging management guidance concerning visual inspections, inspection frequency, and implementation of the latest available and approved EPRI guidelines, for various SG components described in NUREG
| |
| -1801, "Generic Aging Lessons Learned (GALL) Report," Revision 2 (December 2010), and NUREG
| |
| -1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants" (SRP
| |
| -LR), Revision 2 (December 2010). The applicant accordingly revised LRA Section B.2.1.10 and clarified that the Steam Generator Tube Integrity Program is consistent with the GALL Report AMP XI.M19 and LR
| |
| -ISG-2016-01. The staff notes that Seabrook implemented TSTF
| |
| -510, "Revision to Steam Generator Program Inspection Frequencies and Tube Sample Selection" in October 2013, with License Amendment No. 138 to the technical specifications.
| |
| Operating Experience. LRA Section B.2.1.10 summarizes experience related to the Steam Generator Tube Integrity Program. The staff reviewed this information and interviewed the applicant's technical personnel to confirm that the applicable aging effects and industry and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. During the audit, the staff independently confirmed that the applicant had adequately incorporated and evaluated operating experience related to this program.
| |
| The staff reviewed the following regarding operating experience:
| |
| (1) Through RFO 13 (Fall of 2009), Seabrook has plugged a total of 173 tubes in the steam generators (A
| |
| -34 tubes, B
| |
| -25 tubes, C
| |
| -50 tubes, and D
| |
| -64 tubes).
| |
| (2) The Steam Generator Degradation Assessment for RFO 13 in fall 2009 identified operating experience at Vogtle Unit 1 where axial and circumferential outside diameter stress corrosion cracking was reported at the top of the hot leg tubesheet. Vogtle has Westinghouse Model F steam generators with Alloy 600 thermally treated tubing similar Aging Management Review Results 3-68 to Seabrook. Vogtle Unit 1 was the first U.S. plant to report axial outside diameter stress corrosion cracking at the top of the tube sheet in a Model F steam generator.
| |
| Accordingly, this operating experience was incorporated into the implementation plan for RFO 13 as part of the steam generator inspections.
| |
| Subsequently, an axial outside diameter stress corrosion cracking indication was found on one tube in the steam generator "C" hot leg. The indication was approximately 0.2 in. below the top of the tube sheet and was 0.10 in. long. The tube was plugged on both the hot leg and cold leg sides.
| |
| (3) During RFO 12 in the spring of 2008, foreign objects were discovered in steam generator "B" during the inspection of the steam drum area. The root cause evaluation was performed, which concluded that the cause of the foreign objects being in the steam generator was inadequate foreign material exclusion controls of material used in steam generator "B" steam drum inspection.
| |
| The root cause evaluation's recommended corrective action to prevent reoccurrence by revising the job plan for steam generator inspection to include a pre
| |
| -use inspection of all materials brought into the steam generators for concealed or loose foreign material. This corrective action has been implemented.
| |
| During its review of the LRA, the staff also identified operating experience that indicates the potential for degradation of the SG tube
| |
| -to-tubesheet welds that could impact the applicant's program in adequately managing aging effects during the period of extended operation. By letter dated December 14, 2010, the staff issued RAI B.2.1.10
| |
| -1, requesting that the applicant clarify whether the tube
| |
| -to-tubesheet welds are included in the RCPB or if alternate repair criteria have been permanently approved. It also requested that the applicant provide a plant
| |
| -specific AMP, along with the Primary Water Chemistry Program, or justify an alternative method to manage cracking due to PWSCC on the primary coolant side of steam generator tube
| |
| -to-tubesheet welds since they are made from a nickel alloy.
| |
| In its response dated January 13, 2011, the applicant stated that its SG tube
| |
| -to-tubesheet welds are not included in the RCPB because the NRC has approved alternate repair criteria for Seabrook. However, the applicant further stated that the NRC has not yet permanently approved the alternate repair criteria. In the event that the NRC does not grant a permanent approval of the alternate repair criteria through a license amendment, the applicant's RCPB would revert back to include the tube
| |
| -to-tubesheet welds. For such a scenario, the applicant also stated in its response that, unless an alternate repair criteria changing the ASME Code boundary is permanently approved by the NRC, or the applicant's SGs are replaced to eliminate PWSCC
| |
| -susceptible tube
| |
| -to-tubesheet welds, the applicant will submit a plant
| |
| -specific AMP to manage the potential aging effect of cracking due to PWSCC at least 24 months prior to entering the period of extended operation. The plant
| |
| -specific program will do one of the following:
| |
| (1) perform a one
| |
| -time inspection of a representative sample of tube
| |
| -to-tubesheet welds in all SGs to determine if PWSCC cracking is present and, if cracking is identified, resolve the condition through engineering evaluation justifying continued operation or repair the condition, as appropriate (2) perform an analytical evaluation showing that the structural integrity of the SG tube
| |
| -to-tubesheet interface is adequately maintaining the pressure boundary in the presence of Aging Management Review Results 3-69 tube-to-tubesheet weld cracking and ensure that the tube
| |
| -to-tubesheet welds are not required to perform a reactor coolant pressure boundary function After reviewing the applicant's response to RAI B.2.10
| |
| -1, the staff finds that the approved temporary alternate repair criteria appropriately excludes the tube
| |
| -to-tubesheet welds from RCPB on a temporary basis. The staff also noted that the applicant submitted a license amendment request on April 10, 2012, to gain permanent approval from the NRC for an alternate RCPB that does not include the tube
| |
| -to-tubesheet welds.
| |
| However, by teleconference on May 29, 2012, the staff requested that the applicant either provide the AMP for the tube
| |
| -to-tubesheet welds (which would address the 10 attributes of an AMP) as part of its LRA or include the management of the tube
| |
| -to-tubesheet welds as part of the steam generator AMP. In addition, the staff requested that the applicant include the specific actions to be taken to address this issue (i.e., as identified in (1) and (2) above) as commitments in the UFSAR supplement. The staff also requested that the applicant clarify its plans for submitting the analytical evaluation in (2) above as a license amendment for NRC review and approval prior to redefining the pressure boundary and to include this action as part of its commitment in the UFSAR supplement. The applicant indicated that it would provide additional information in a subsequent submittal. In its response dated December 10, 2012, the applicant stated that Amendment No. 131 to the Seabrook license was issued on September 10, 2012 (ADAMS Accession No. ML12178A537). This license amendment provides permanent application of steam generator tube alternate repair criteria. These alternate repair criteria allow the licensee to exclude the tube
| |
| -to-tubesheet welds from the RCPB. The staff finds the applicant's response acceptable because the NRC has approved the alternate repair criteria (through license amendment) that exclude the tube-to-tubesheet welds from the RCPB on a permanent basis, including for the period of extended operation. Therefore, no plant-specific AMP or alternate aging management method is required. The staff's concern described in RAI B.2.1.10
| |
| -1 is resolved. Open Item OI 3.0.3.2.2-1 is closed.
| |
| By letter dated December 14, 2010, the staff issued RAI B.2.1.10
| |
| -2, requesting that the applicant address foreign operating experience in SGs with similar design to that of Seabrook SGs, where cracking due to PWSCC has been identified in SG divider plate assemblies made with Alloy 600.
| |
| In addition, the staff requested that the applicant discuss the materials of construction of the Seabrook SG divider plate assemblies and an appropriate program to manage the potential aging effect if the divider plate assembly is made of Alloy 600 material.
| |
| In its response dated January 13, 2011, the applicant stated that the Seabrook Westinghouse Model F SG divider plate and weld materials are Inconel (ASME
| |
| -SB-168) Alloy 600/82/182. The applicant also stated that Seabrook will perform an inspection of each SG prior to entering the period of extended operation to assess the condition of the divider plate assembly unless operating experience or analytical results or both show that crack propagation into the RCS pressure boundary is not possible; then the inspections need not be performed. The applicant indicated that any evidence of cracking will be documented and evaluated under the corrective action program.
| |
| | |
| Aging Management Review Results 3-70 After reviewing the applicant's response to RAI B.2.1.10
| |
| -2, the staff finds that it appears to give Seabrook the option of performing a one
| |
| -time inspection or performing an analytical evaluation to assess potential crack propagation into the RCS pressure boundary. The staff discussed this concern with the applicant, and the applicant revised its response. In a letter dated March 22, 2011, the applicant amended its response to RAI B.2.1.10
| |
| -2 by stating that Seabrook will perform a one
| |
| -time inspection of the divider plate assembly and that any evidence of cracking will be documented and evaluated under the corrective action program. The applicant also indicated that any inspection techniques used will be capable of detecting PWSCC in the SG divider plate assemblies and their associated welds. The staff finds the applicant's plans to perform a one
| |
| -time inspection of each SG to assess the condition of the divider plate assembly acceptable because any crack present in the assembly will be detected, evaluated, and entered into the corrective action program. Additionally, the applicant committed to performing the inspection prior to the period of extended operation. However, because RAI B.2.1.10
| |
| -2 is related to RAI B.2.1.10
| |
| -1 and Open Item OI 3.0.3.2.2
| |
| -1, the staff requested that the applicant provide information regarding its one
| |
| -time inspection of the divider plate assembly in its UFSAR supplement. With the subsequent closure of Open Item OI 3.0.3.2.2
| |
| -1 and the staff's evaluation of the UFSAR supplement below, the staff's concern described in RAI B.2.1.10
| |
| -2 is resolved.
| |
| Based on its audit, review of the application, and review of the applicant's responses to RAIs B.2.1.10-1 and B.2.1.10
| |
| -2, the staff finds that the applicant has appropriately evaluated plant
| |
| -specific and industry operating experience. Operating experience related to the applicant's program demonstrates that it can adequately manage the effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.10 provides the UFSAR supplement for the Steam Generator Tube Integrity Program.
| |
| The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Table 3.1-2. The staff also noted that the applicant committed (Commitment Nos. 54 and 55) to enhancing the Steam Generator Tube Integrity Program prior to entering the period of extended operation. Specifically, the applicant committed to the following:
| |
| * Commitment 54: Unless an alternative repair criteria changing the ASME Code boundary is permanently approved by the NRC, or the Seabrook steam generators are changed to eliminate PWSCC
| |
| -susceptible tube
| |
| -to-tubesheet welds, the applicant will submit a plant
| |
| -specific AMP to manage the potential aging effect of cracking due to PWSCC, at least 24 months prior to entering the period of extended operation.
| |
| * Commitment 55: Seabrook will perform an inspection of each steam generator to assess the condition of the divider plate assembly.
| |
| In its response dated June 19, 2012, the applicant amended Commitment 54 to the following:
| |
| * Commitment 54: NextEra will address the potential for cracking of the primary to secondary pressure boundary due to PWSCC of tube
| |
| -to-tubesheet welds using one of the following two options:
| |
| | |
| Aging Management Review Results 3-71 (1) Perform a one
| |
| -time inspection of a representative sample of tube-to-tubesheet welds in all SGs to determine if PWSCC cracking is present and, if cracking is identified, resolve the condition through engineering evaluation justifying continued operation or repair the condition, as appropriate, and establish an ongoing monitoring program to perform routine tube
| |
| -to-tubesheet weld inspections for the remaining life of the steam generators, or (2) Perform an analytical evaluation showing that the structural integrity of the SG tube-to-tubesheet interface is adequately maintaining the pressure boundary in the presence of tube
| |
| -to-tubesheet weld cracking, or redefining the pressure boundary in which the tube
| |
| -to-tubesheet weld is no longer included and, therefore, is not required for reactor coolant pressure boundary function. The redefinition of the reactor coolant pressure boundary must be approved by the NRC as part of a license amendment request. In the response dated December 10, 2012, the applicant stated that, with the implementation of License Amendment No. 131, which provided permanent application of SG tube alternate repair criteria, Commitment 54 was complete.
| |
| In its response dated June 19, 2012, the applicant amended Commitment 55 to the following:
| |
| * Commitment 55 (in response to issuance of the final LR
| |
| -ISG-2011-02): Seabrook will perform an inspection of each steam generator to assess the condition of the divider plate assembly within 5 years prior to entering the period of extended operation.
| |
| As discussed in the Operating Experience section above, the staff requested that the applicant include, in the UFSAR supplement, information regarding its one
| |
| -time inspection of the divider plate assembly. The staff has reviewed the information in the UFSAR supplement, as amended by letter dated June 19, 2012, and finds that it is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| In its responses dated May 25 and June 20, 2017, the applicant submitted Supplement 53 to the LR application, which stated that Seabrook would follow the inspection guidance provided within LR-ISG-2016-01 and remove Commitment 55, as following the guidance of LR
| |
| -ISG-2016-01 made Commitment 55 unnecessary. In addition, the applicant revised the UFSAR description based on the guidance provided within LR
| |
| -ISG-2016-01. The staff has reviewed the information in the UFSAR supplement, as amended by letters dated May 25 and June 20, 2017, and finds that it is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its audit and review of the applicant's Steam Generator Tube Integrity Program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and its justification (including the amendments to respond to LR
| |
| -ISG-2011-02 and LR-ISG-2016-01) and determined that the AMP is adequate to manage the applicable aging effects. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also Aging Management Review Results 3-72 reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.2.3 Open-Cycle Cooling Water System Program Summary of Technical Information in the Application. LRA Section B.2.1.11 describes the existing Open
| |
| -Cycle Cooling Water System Program as consistent, with an exception, with GALL Report AMP XI.M20, "Open
| |
| -Cycle Cooling Water System." The applicant stated that the Open-Cycle Cooling Water System Program manages elastomer degradation, reduction of heat transfer, and loss of material due to erosion, corrosion, and fouling. The applicant also stated that the program relies on the implementation of the recommendations of NRC GL 89
| |
| -13, "Service Water System Problems Affecting Safety
| |
| -Related Equipment." The applicant stated that the program includes the following:
| |
| * surveillance and control of aging mechanisms
| |
| * tests to verify heat transfer
| |
| * routine inspection and maintenance of plant components
| |
| * system walkdown to ensure compliance with the station's licensing basis
| |
| * a review of maintenance, operating, and training practices and procedures to ensure the effectiveness of established programs The applicant stated that the micro
| |
| - and macro-biological fouling is controlled by its Chlorine Management Program. The applicant further stated that a variety of inspection and testing methods are used, including visual, eddy current, and ultrasonic tests on plant heat exchangers and piping.
| |
| During the course of the staff's review, the applicant submitted amendments to the application, and these are discussed in the staff's evaluation below, as appropriate.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.M20. As discussed in the audit report, the staff confirmed that each element of the applicant's program is consistent with the corresponding element of GALL Report AMP XI.M20, with the exception of the "scope of program" program element. For this element, the staff determined the need for additional clarification, which resulted in the issuance of an RAI.
| |
| GALL Report AMP XI.M20 recommends that the program address the aging effects of material loss and fouling due to micro
| |
| - or macro-organisms and various corrosion mechanisms. During its audit, the staff found that the applicant will manage hardening and loss of strength due to elastomer degradation. During onsite discussions, the applicant stated that this aging effect would be managed by visual inspections. However, the staff considers the detection of hardening or loss of strength due to elastomer degradation to be impractical without some type
| |
| | |
| Aging Management Review Results 3-73 of physical manipulation of the components being managed. It was unclear how the Open
| |
| -Cycle Cooling Water System Program would manage this aging effect by visual inspections only. By letter dated December 14, 2010, the staff issued RAI B.2.1.11
| |
| -1, requesting that the applicant provide the technical basis for how hardening and loss of strength due to elastomer degradation will be managed by the Open
| |
| -Cycle Cooling Water System Program.
| |
| In its response dated January 13, 2011, the applicant provided changes to LRA Section B.2.1.11, which included physical or manual manipulation of elastomers to detect hardening and loss of strength due to elastomer degradation. The staff finds this response acceptable because the applicant's modification to its program includes new techniques that are appropriate for detecting the hardening and loss of strength of elastomers. The staff's concern described in RAI B.2.1.11
| |
| -1 is resolved.
| |
| The staff also reviewed the portions of the "preventive actions" program element associated with the exception to determine if the program will be adequate to manage the aging effects for which it is credited. The staff's evaluation of this exception follows.
| |
| Exception. LRA Section B.2.1.11 states an exception to the "preventive actions" program element. The LRA states that the open
| |
| -cycle cooling water system includes both unlined and lined piping. The applicant stated that the unlined materials used in the system include Inconel, copper-nickel, aluminum-bronze, and stainless steels, which were specifically selected for their resistance to the effects of salt water. The applicant stated that, because of the material resistance, the Open
| |
| -Cycle Cooling Water System Program will be able to manage unlined piping as well as lined piping.
| |
| The staff reviewed this exception to the GALL Report and noted that the applicant took the exception because it has unlined piping in the open
| |
| -cycle cooling water system. The staff noted that GALL Report AMP XI.M20 states that components are lined or coated to protect the underlying metal surfaces. The staff evaluated the materials used in the unlined portions of open-cycle cooling water system. The staff reviewed the corrosivity of the materials in seawater using the American Society for Metals (ASM) international data and noted that the cited materials have low corrosion susceptibility in seawater. The staff finds the program's exception acceptable because the materials used by the applicant are resistant to the aggressive cooling water environment and preclude the need for being lined or coated to protect the metal surface.
| |
| Based on its audit, review of the application, and review of the applicant's response to RAI B.2.1.11
| |
| -1, the staff finds that elements one through six of the applicant's Open
| |
| -Cycle Cooling Water System Program, with an acceptable exception, are consistent with the corresponding program elements of GALL Report AMP XI.M20 and, therefore, are acceptable.
| |
| Enhancement. By letter dated March 5, 2014, the applicant enhanced the program to include visual inspection of internal coatings for loss of coating integrity. The staff's evaluation of the changes associated with the activities for managing loss of coating integrity is documented in SER Section 3.0.3.4.1, which includes the staff's evaluation of the applicant's response to LR
| |
| -ISG-2013-01.
| |
| Aging Management Review Results 3-74 Operating Experience. LRA Section B.2.1.11 summarizes operating experience related to the Open-Cycle Cooling Water System Program. The applicant stated that, because of leakage problems, it had replaced the 90
| |
| -10 CuNi tubing in the primary component cooling water system heat exchangers with titanium. According to the applicant, followup eddy current inspections have shown that the leakage problems had been resolved. The applicant also stated that it identified seawater intrusion through gaps in the service water cement
| |
| -lined joints. The applicant stated that it refurbished the joints with flexible rubber leak seals and that followup inspections had confirmed that the seals had been effective in preventing further corrosion.
| |
| The staff reviewed operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program. During its review, the staff identified operating experience for which it determined the need for additional clarification and resulted in the issuance of an RAI, as discussed below.
| |
| The operating experience section for this program noted that the aboveground cement
| |
| -lined piping associated with the diesel generator heat exchangers had been replaced with Plastisol polyvinyl chloride (PVC)
| |
| -lined carbon steel piping and that followup examinations had confirmed that the engineering design change was effective in preventing loss of material. However, based on information provided by the regional staff in late 2011, the PVC lining had degraded to the extent that it was missing in certain portions of the piping and, according to the applicant, pieces of the lining had detached and partially restricted flow to a diesel generator heat exchanger. As part of the normal Reactor Oversight Process, the regional staff followed up on the applicant's operability evaluation, root cause determination, and corrective actions associated with this event. The regional staff subsequently documented a violation of very low safety significance (Green) for a violation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," for several aspects of the design change 93DCR003, which installed the PVC
| |
| -lined piping. The regional staff's inspection activities associated with this event are documented in Inspection Reports (IR) 443/2011004, dated November 4, 2011, and IR 443/2011005, dated February 14, 2012.
| |
| By letter dated December 12, 2011, the staff issued RAI B.2.1.11
| |
| -2, requesting that the applicant describe the recent PVC lining degradation and to discuss any previous aging management activities that were performed to manage liner degradation prior to the event. In addition, the staff requested that the applicant describe corrective actions taken in response to this event and to provide any enhancements made to the AMP to ensure components' intended functions will not be impacted during the period of extended operation.
| |
| In its response dated February 7, 2012, the applicant described the PVC lining degradation event, including its associated root cause evaluation, discussed the previous aging management activities for this portion of the piping, and described the corrective actions taken as a result of this event. The applicant's evaluation identified two root causes for this event.
| |
| (1) A limited life design change was implemented in 1994 with no provisions to formally track the periodic verification of the coating condition.
| |
| The PVC lining material had a 15
| |
| -year service life.
| |
| | |
| Aging Management Review Results 3-75 (2) Oversight of the service water system was not adequate due to a lack of compliance with the system performance monitoring guideline requirements associated with the PVC-lined pipe.
| |
| With respect to previous aging management activities, the applicant stated that, following its installation in 1994, the PVC
| |
| -lined piping was inspected in each outage from 1996 through 2003 with no significant indications of liner degradation. However, inspection notes in 2002 stated there was a lack of adhesion of the liner to the pipe surface. After 2003, periodic inspection of the PVC
| |
| -lined piping was discontinued in favor of a new long
| |
| -term inspection strategy, which focused on the service water system as a whole, and the PVC-lined piping was not singled out for more frequent inspections. The next inspection of the PVC
| |
| -lined piping was scheduled for the RFO in 2012.
| |
| With respect to corrective actions taken in response to this event, the applicant stated that a design change will be developed to replace the PVC
| |
| -lined piping in 2012 with a corrosion
| |
| -resistant, unlined material, and that the associated service water piping will be periodically inspected to verify adequate pipe wall thickness, until replaced. In addition, as part of the extent of condition evaluation, the applicant assigned actions to evaluate the concrete
| |
| -lined piping in the screen wash and circulating water systems to determine liner adequacy and to determine if other coatings used in the service water system have service life limitations. Further, the applicant stated that corrective actions have been assigned to revise the design control process to utilize the preventive maintenance process for inspections and replacement activities and to establish a process to ensure that monitoring and inspection programs comply with system performance monitoring guidelines and that long
| |
| -term strategies comply with regulatory commitments such as GL 89
| |
| -13. The applicant concluded that, since the AMP has provisions for managing protective coatings, enhancements are not required.
| |
| The staff reviewed the applicant's response and noted that several corrective actions had not been implemented. With regard to the Open
| |
| -Cycle Cooling Water System Program, the staff noted that the replacement of the PVC
| |
| -lined piping was scheduled for later in 2012, and activities associated with the following items were still pending:
| |
| * implement a process to ensure that monitoring and inspection programs comply with performance monitoring guidelines
| |
| * implement a process to ensure that long
| |
| -term strategies comply with GL 89
| |
| -13
| |
| * determine liner adequacy in the screen wash and circulating water systems
| |
| * determine if other coatings in the service water system have service life limitations The staff considered completion of these activities as providing reasonable assurance that the program can adequately manage the detrimental effects of aging on SSCs within the scope of the program. As discussed above, the applicant's corrective action activities were being addressed through the Reactor Oversight Process; however, because these activities directly affect the Open
| |
| -Cycle Cooling Water System Program, the staff considered that these activities should be captured in a commitment. During a teleconference on April 10, 2012, the applicant agreed to complete the above activities prior to the period of extended operation.
| |
| In fact, by letter dated April 26, 2012, the applicant revised its response to RAI B.2.1.11
| |
| -2 by stating that it had completed implementation of the process to ensure that monitoring and inspection programs comply with system performance guidelines and that long
| |
| -term strategies Aging Management Review Results 3-76 comply with commitments made for GL 89
| |
| -13. Regarding the adequacy of the liner in the screen wash and circulating water systems, the applicant stated that both systems have cement lining similar to the service water system and that inspections of the lining are conducted through the Open
| |
| -Cycle Cooling Water System Program for those portions that are within the scope of GL 89
| |
| -13, or otherwise, through the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program.
| |
| Regarding other coatings in the service water system that may have service life limitations, the applicant stated that an engineering evaluation in 1993 had determined Belzona products, which are polymeric materials used for lining and liner repairs, have an expected service life of 15 years. The applicant added that it had reviewed its operating experience database and had not identified failures of Belzona products due to exceeding its service life. The applicant stated that the extent of use of Belzona and polyurethane coatings has been identified and is being tracked in the Service Water Inspection and Repair Trending Program, and that preventive maintenance activities ensure that inspections are scheduled and tracked.
| |
| Regarding the replacement of the PVC
| |
| -lined piping, the applicant added Commitment 69 to LRA Section A.3, "License Renewal Commitment List," to replace the PVC
| |
| -lined diesel generator heat exchanger service water piping with pipe fabricated from AL6XN material, prior to the period of extended operation. The applicant noted that this material is treated as stainless steel and is included in the existing AMR item to be managed for aging for piping and fittings in LRA Table 3.3
| |
| .2-37 for the service water system.
| |
| The staff finds the applicant's response to RAI B.2.1.11
| |
| -2 acceptable because the applicant provided sufficient details of its corrective actions for process improvements and program changes that address the failure of PVC-lined piping. In addition, the applicant's commitment to replace the PVC
| |
| -lined piping prior to the period of extended operation resolves the specific operating experience issue, because the replacement piping is not lined, the replacement material has low corrosion susceptibility to seawater, and the piping will be managed in the same manner as other stainless steel components in the system. The staff's concern described in RAI B.2.1.11
| |
| -2 is resolved. By letter dated October 2, 2014, the applicant confirmed in the LRA 2014 annual update that the replacement of the PVC
| |
| -lined piping had been completed and the applicant changed the Commitment 69 status to "Complete."
| |
| By letter dated March 5, 2014, the applicant provided its response to LR
| |
| -ISG-2012-02, "Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation," and provided its basis for managing loss of material due to recurring internal corrosion (RIC). The applicant stated that RIC has only occurred in the cement-lined carbon steel service water system piping or fittings, and the Open
| |
| -Cycle Cooling Water System Program manages these components. In 2006, the applicant recognized that UTs of only the aboveground field welds could not effectively identify areas of future leaks. However, internal inspections focusing on rust stains, and corrosion nodules were found to be an effective method for identifying potential liner degradation that allowed corrosion and wall thinning in the piping. Following a leak downstream of a butterfly valve in 2011, the applicant performed a root cause analysis to address the through
| |
| -wall leaks in the service water system and identified a number of corrective actions. The corrective actions include, but are not limited to, a requirement to perform a post
| |
| -outage assessment of the service water material condition, an inspection plan for the service water piping that incorporates turbulent flow considerations and stagnant locations, inspection criteria for various coating materials, an inspection and Aging Management Review Results 3-77 testing plan for the elastomer seals, and a requirement for tracking service water system leaks and trending repairs to the service water piping. The applicant also stated that, if corrosion is detected in these components, the amount of wall loss can be determined through subsequent ultrasonic inspections of the corroded piping locations.
| |
| However, the staff noted that the applicant did not firmly establish that UT measurements for wall loss would be performed if corrosion was detected in service water piping during the visual inspections. In addition, it was not evident to the staff whether the detection of corrosion in a specific service water component would initiate expanded visual examinations of other portions of the system. By letter dated November 18, 2014, the staff issued RAI B.2.1.11
| |
| -4, Parts 1 and 2, requesting that the applicant address these issues.
| |
| In Part 1 of its response dated March 9, 2015, the applicant stated that the "monitoring and trending" program element includes wall thickness measurements when any indication of base metal corrosion is observed. The applicant also stated that the wall thickness measurement requirement currently exists in the station's "Service Water Inspection and Repair Trending," guideline, and both the Open
| |
| -Cycle Cooling Water System Program and the existing station guideline also require trending of the wall thickness if a damaged internal coating is not repaired.
| |
| The staff noted that the applicant's response to RAI B.2.1.1 1-4, Part 1, confirms that the program includes appropriate criteria to perform wall thickness measurements if degradation in the base metal of the service water system is detected or if an internal coating is damaged and has been left in an unrepaired condition for normal operating conditions. The staff finds this acceptable because it is consistent with the recommended "monitoring and trending" program element in GALL Report AMP XI.M20.
| |
| In Part 2 of its response dated March 9, 2015, the applicant explained that the program is already implementing comprehensive inspections of the aboveground and buried portions of the service water piping. Specifically, the applicant stated that, in 2011, it implemented an aggressive condition monitoring program to perform internal visual inspections of all aboveground and underground (buried) cement
| |
| -lined service water piping within six RFOs to identify and repair those areas indicating liner degradation that may be susceptible to corrosion and wall thinning. The applicant stated that these inspections are consistent with the guidance in LR-ISG-2013-01 and started in RFO 15 (September 2012). The applicant also stated that the service water system locations identified as being more susceptible to liner degradation or to base metal corrosion have been taken into consideration in the inspection schedule.
| |
| To provide an example of these monitoring criteria, the applicant stated that the aboveground piping was determined to be more susceptible in areas of turbulent flow due to numerous butterfly valves, restricting orifices, and branch connections. Therefore, the applicant indicated that the internal inspections of the aboveground piping is scheduled to be completed within four RFOs, with the inspections covering approximately 2,000 ft of additional aboveground service water piping. In contrast, the applicant explained that the internal inspections of the buried portions of the service water piping are scheduled to be completed within six RFOs, with the inspections covering approximately 6,000 ft of additional buried service water piping. The applicant stated that it would implement these inspections until RIC, as defined in LR-ISG-2012-02, has been eliminated. The applicant also stated that expanded inspections under the criteria in ASME Code Case N
| |
| -513 would be performed if further evidence of corrosion is detected at any time in the service water system.
| |
| | |
| Aging Management Review Results 3-78 The staff noted that the applicant's response to RAI B.2.1.11
| |
| -4, Part 2, provides an acceptable basis for demonstrating conformance with the criteria for inspecting cement
| |
| -lined or coated service water piping in LR
| |
| -ISG-2013-01 and for managing RIC in the service water system in LR-ISG-2012-02. Specifically, the staff noted that the Open
| |
| -Cycle Cooling Water System Program satisfies the degree of inspection coverage criteria because the applicant is alread y implementing a comprehensive visual inspection program that covers 100 percent of the cement-lined or coated service water piping. The staff also noted that, if additional evidence of degradation is found at any time during these inspections, the applicant will implement expansion criteria that are consistent with the criteria in ASME Code Case N
| |
| -513-3. The staff determined that this is acceptable because the methodology in ASME Code Case N
| |
| -513-3 has been endorsed by the staff for use in RG 1.147, as long as the applicant will implement the staff's limitation on the timing of performing applicable repairs or replacements, as identified in Table 2 of RG 1.147.
| |
| Therefore, based on this review, the staff finds that the Open
| |
| -Cycle Cooling Water System Program (as clarified in the response to RAI B.2.1.11
| |
| -4, Part 2) is acceptable because: (a) the program will perform adequate wall thickness measurements if evidence of corrosion is detected in the base
| |
| -metal portions of the service water piping or if damage to cement liner or coating systems is detected and left in service without repair, (b) the program is in the process of implementing comprehensive inspections of all the service water system piping, (c) the applicant will implement sample expansion in accordance with ASME Code Case N
| |
| -513-3, and (d) the applicant will continue augmented inspections of the service water system until no evidence of RIC remains in the system. The staff's concerns described in RAI B.2.1.11
| |
| -4 are resolved, and the applicant has adequately addressed the further evaluation for RIC contained in LR-ISG-2012-02. Based on its audit, review of the application, and review of the applicant's response to RAIs B.2.1.11-2 and B.2.1.11
| |
| -4, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10 and, therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.11, as modified by letter dated March 9, 2015, provides the UFSAR supplement for the Open
| |
| -Cycle Cooling Water System Program. The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Tables 3.2
| |
| -2, 3.3-2, and 3.4-2. The staff also noted that the applicant committed: (a) to replace the PVC
| |
| -lined service water piping for the diesel generator heat exchanger prior to the period of extended operation (Commitment 69) and (b) to enhance the program to include visual inspections of internal coatings for loss of coating integrity and to implement this enhancement within 10 years prior to the period of extended operation (Commitment 79).
| |
| Based on its review, the staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its audit and review of the applicant's Open
| |
| -Cycle Cooling Water System Program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the Aging Management Review Results 3-79 exception and its justification and determined that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. The staff also reviewed the enhancement and determined that its implementation within 10 years prior to the period of extended operation will ensure that the AMP will be capable of managing the applicable aging effects.
| |
| The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed t he UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.2.4 Closed-Cycle Cooling Water System Program Summary of Technical Information in the Application. LRA Section B.2.1.12 describes the existing Closed
| |
| -Cycle Cooling Water System Program as consistent, with exceptions and an enhancement, with GALL Report AMP XI.M21, "Closed
| |
| -Cycle Cooling Water System." The applicant stated that this program manages the aging effects of cracking due to stress corrosion cracking (SCC), loss of material due to general, crevice, pitting, and galvanic corrosion, and reduction of heat transfer due to fouling. The applicant also stated that the program scope includes the primary component cooling water system, emergency diesel generator jacket water cooling system, fire pump diesel engine glycol coolant system, control building air handling glycol coolant system, and thermal barrier cooling water system. The applicant stated that it uses either a hydrazine chemistry or a mixed glycol chemistry to control aging in the various closed-cycle systems. The applicant further stated that it implements EPRI 1007820, "Closed Cooling Water Chemistry Guideline, Revision 1," to monitor and control the cooling water chemistry. The applicant stated that it uses corrosion test coupons to check the effectiveness of the inhibitor and corrosion rates.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.M21. As discussed in the audit report, the staff confirmed that each element of the applicant's program is consistent with the corresponding element of GALL Report AMP XI.M21, with the exception of the "preventive actions" and "acceptance criteria" program elements. For these elements, the staff determined the need for additional clarification, which resulted in the issuance of RAIs.
| |
| The GALL Report AMP XI.M21 states that the closed
| |
| -cycle cooling water system corrosion inhibitor concentrations should be maintained within the specified limits of the EPRI guideline. However, during its audit, the staff found that the applicant's diesel generator cooling water jacket system (a blended glycol formulation) only has a pH Action Level 2, and does not identify an Action Level 1 for pH. Action levels are actions to be taken upon reaching a chemistry range level that is above the normal range level. It was not clear to the staff why the applicant's onsite guidelines for the diesel generator cooling water jacket are not consistent with the EPRI guideline by having two action levels for pH. By letter dated December 14, 2010, the staff issued RAI B.2.1.12
| |
| -2, requesting that the applicant justify why the pH action levels for the diesel generator cooling water jacket are not consistent with those found in the EPRI guideline.
| |
| Aging Management Review Results 3-80 In its response dated January 13, 2011, the applicant added Commitment 57 in LRA Appendix A, to revise the program documents to reflect the EPRI guideline's operating ranges and action level values for the diesel generator cooling water jacket pH. The staff finds this response acceptable because adding the pH Action Level 1, in accordance with the EPRI guideline, will ensure that the identification of pH levels outside the normal operating range will initiate appropriate actions. The staff's concern described in RAI B.2.1.12
| |
| -2 is resolved.
| |
| The GALL Report AMP XI.M21 recommends that acceptance criteria for performance tests be based on system and component design
| |
| -basis requirements under the "acceptance criteria" program element. However, the applicant stated that it does not plan to use performance tests to confirm the effectiveness of the program and instead will rely upon corrosion coupons and internal visual inspections.
| |
| The staff noted that the applicant's "acceptance criteria" program element did not include criteria to evaluate the results from the corrosion coupon surveillances and visual inspections. By letter dated December 14, 2010, the staff issued RAI B.2.1.12
| |
| -4, requesting that the applicant provide the acceptance criteria that will be used for the corrosion coupon and visual inspection surveillance activities.
| |
| Prior to responding to RAI B.2.1.12
| |
| -4, the staff guidance in GALL Report, Revision 2, AMP XI.M21A on conducting performance tests for the Closed
| |
| -Cycle Cooling Water Program was removed. The current staff guidance in the GALL Report states that the Closed
| |
| -Cycle Cooling Water Program includes (a) water treatment, including the use of corrosion inhibitors, to modify the chemical composition of the water such that the function of the equipment is maintained and such that the effects of corrosion are minimized, (b) chemical testing of the water, and (c) inspections to determine the presence or extent of corrosion and/or cracking. The "parameters monitored/inspected" program element of GALL Report AMP XI.M21A state that the program monitors water chemistry and the visual appearance of surfaces exposed to the water, and that corrosion monitoring by coupon testing may be included. The "detection of aging effects" program element of GALL Report AMP XI.M21A states that, if visual inspections identify adverse conditions, additional examinations are conducted. In its response dated January 13, 2011, the applicant revised LRA Section B.2.1.12 to state that personnel completing inspections under the Closed
| |
| -Cycle Cooling Water System Program will be trained to identify parameters associated with the aging effects being monitored by the program. The revised section referred to the EPRI training program, "Identification and Detection of Aging Issues," and stated that it is supplemented with the EPRI "Aging Assessment Field Guide," and "Aging Identification and Assessment Checklists for Mechanical Components." The applicant stated that the nuclear industry has collected information on how to identify if an aging effect is occurring and has developed training programs on how to correlate the observed condition to a possible aging effect. The applicant also stated that this training will ensure that these inspections will adequately address potential aging effects and associated acceptance criteria for the in
| |
| -scope material. The applicant further stated that adverse or potentially adverse conditions identified during the visual inspections will be documented and evaluated in accordance with the corrective actions program and that system components must meet design requirements such as minimum wall thickness. The staff finds this response acceptable because:
| |
| * The Closed
| |
| -Cycle Cooling Water Program includes visual inspections.
| |
| * Inspectors are trained to check for visual indications of adverse or potentially adverse conditions using industry standard guidelines.
| |
| | |
| Aging Management Review Results 3-81
| |
| * Adverse or potentially adverse conditions will be evaluated under the corrective action program.
| |
| * The acceptance criterion for the evaluations is that system components must meet design requirements such as minimum wall thickness.
| |
| * As allowed by SRP
| |
| -LR A.1.2.3.6, it is not necessary to discuss CLB design loads if the acceptance criteria of the inspections do not permit degradation.
| |
| Given that GALL Report Revision 2, AMP XI.M21A recommends that corrosion coupon testing be an option in addition to visual inspections, and the applicant's response is consistent with GALL Report AMP XI.M21A and the SRP
| |
| -LR, the staff's concern described in RAI B.2.1.12
| |
| -4 is resolved.
| |
| GALL Report AMP XI.M21 states that the Closed
| |
| -Cycle Cooling Water System Program includes preventive measures, testing, and inspection to both minimize and monitor corrosion. The GALL Report indicates that closed
| |
| -cycle cooling water systems can undergo aging due to loss of material from microbiologically
| |
| -influenced corrosion. The applicant's program states that it manages cracking due to SCC; loss of material due to general, crevice, pitting, and galvanic corrosion; and reduction of heat transfer due to fouling. However, it was not clear if the applicant uses the Closed
| |
| -Cycle Cooling Water System Program to manage aging from microbiologically
| |
| -influenced corrosion. By letter dated January 21, 2011, the staff issued RAI B.2.1.12-7, requesting that the applicant justify why the Closed
| |
| -Cycle Cooling Water System Program does not need to manage microbiologically-influenced corrosion in the closed
| |
| -cycle cooling water systems. The applicant was further requested to identify what preventive actions, parameters monitored or inspection techniques are being conducted if microbiologically
| |
| -influenced corrosion is being managed by the Closed
| |
| -Cycle Cooling Water System Program. In its response dated February 18, 2011, the applicant stated that the GALL Report, Revision 1 and Revision 2, did not include any items for PWRs; therefore, it did not consider microbiologically-influenced corrosion to be an aging effect requiring management. The applicant reiterated that the Closed
| |
| -Cycle Cooling Water System Program does not manage loss of material for this mechanism. However, the applicant also stated that its closed
| |
| -cycle cooling chemistry control procedure does include biological activity as a recommended parameter in keeping with the EPRI guideline. In addition, the applicant stated that its review of plant
| |
| -specific operating experience did not identify any microbiologically
| |
| -influenced corrosion issues in the close
| |
| -cycle cooling water systems.
| |
| In its review of the applicant's response, the staff noted that microbiologically
| |
| -influenced corrosion is a stated concern in the EPRI guideline for closed
| |
| -cycle cooling systems using glycol formulations, and since these systems can be found in both boilin g-water reactors (BWRs) and PWRs, the applicant's determination that this aging mechanism was not applicable to PWRs is without merit. The staff noted that the applicant's lack of plant
| |
| -specific operating experience associated with microbiologically
| |
| -influenced corrosion may be attributable to the existing additives that mitigate this mechanism. However, SRP
| |
| -LR Section A.1.2.1, "Applicable Aging Effects," states the following:
| |
| An aging effect should be identified as applicable for license renewal even if there is a prevention or mitigation program associated with that aging effect. For example, water chemistry, a coating, or use of cathodic protection could prevent or mitigate corrosion, but corrosion should be identified as applicable for license Aging Management Review Results 3-82 renewal, and the AMR should consider the adequacy of the water chemistry, coating, or cathodic protection as an aging management program.
| |
| Given this basis, the applicant did not provide reasonable assurance that loss of material due to microbiologically
| |
| -influenced corrosion does not need to be included as part of the Closed
| |
| -Cycle Cooling Water System Program. By letter dated May 23, 2011, the staff issued RAI B.2.12
| |
| -9, requesting that the applicant provide plant
| |
| -specific data to demonstrate that the lack of microbiologically
| |
| -influenced corrosion cannot be attributed to the existing chemical treatment in the closed cooling water systems.
| |
| In its response dated June 2, 2011, the applicant stated that its program complies with EPRI 1007820, "Closed Cooling Water Chemistry Guideline." The applicant also stated that it takes no exception relative to testing for microbiological activity and that its operating procedures include testing for biological activity as a diagnostic parameter. The applicant revised LRA Sections A.2.1.12 and B.2.1.12 to state that glycol
| |
| -containing systems within the scope of the Closed
| |
| -Cycle Cooling Water System Program are monitored for the presence of microbiological activities in accordance with the EPRI Closed Cooling Water Chemistry Guideline. The staff finds this response acceptable because the applicant has modified its program documents to clarify that glycol systems are being managed for microbiologically
| |
| -influenced corrosion, consistent with EPRI guidelines. The staff's concerns described in RAIs B.2.1.12
| |
| -7 and B.2.1.12
| |
| -9 are resolved.
| |
| The staff also reviewed the portions of the "preventive actions," "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements associated with exceptions and an enhancement to determine if the program will be adequate to manage the aging effects for which it is credited. The staff's evaluation of these exceptions and an enhancement follows.
| |
| Exception 1. LRA Section B.2.1.12 states an exception to the "preventive actions," "monitoring and trending," and "acceptance criteria" program elements. The applicant stated that it took an exception to the use of the EPRI TR
| |
| -107396, "Closed Cooling Water Chemistry Guideline," that was issued in 1997, because it uses the updated version, EPRI 1007820, "Closed Cooling Water Chemistry Guideline, Revision 1," which was issued in 2004. The applicant stated that the updated version meets the same requirements of EPRI TR
| |
| -107396 for maintaining conditions to minimize corrosion and microbiological growth.
| |
| The staff reviewed this exception to the GALL Report and noted that the applicant took the exception because the GALL Report is based on the earlier version of the EPRI guideline rather than the one used by the applicant. The staff finds the program exception acceptable because the updated EPRI guideline for the closed cooling water chemistry accounts for more recent operating experience and specifies equivalent guidance for corrosion inhibitor concentrations as those specified in TR
| |
| -107396. Exception 2. LRA Section B.2.1.12 states an exception to the "preventive actions," "monitoring and trending," and "acceptance criteria" program elements. The applicant stated that instead of limiting the normal operating range for hydrazine to the EPRI guidance maximum concentration of 200 ppm, the thermal barrier cooling water system is specified with a maximum of 300 ppm. The applicant also stated that this higher limit was established to minimize radiation exposure, which resulted from an ongoing hydrazine consumption issue apparently due to an unvented air problem. The applicant further stated it had determined that the higher concentration level was Aging Management Review Results 3-83 acceptable, based on a review of the potential effects on components, which included corrosion rate monitoring through corrosion coupons in the system.
| |
| The staff reviewed this exception to the GALL Report and noted that the applicant took the exception because an ongoing operational problem had caused more frequent chemical additions, resulting in increased worker radiation exposure. However, the applicant's technical basis documents did not discuss how copper corrosion was evaluated or the basis for why it is appropriate to have higher hydrazine levels in its thermal barrier system than recommended in the EPRI guideline. The staff noted that the EPRI guideline discussed the susceptibility to SCC of some copper alloys exposed to ammonia, which can occur when hydrazine is exposed to air. By letter dated December 14, 2010, the staff issued RAI B.2.1.12
| |
| -1, requesting that the applicant provide justification for the higher hydrazine levels in the thermal barrier system compared to what is recommended in the EPRI guideline and why these higher levels will not lead to enhanced degradation. In addition, the staff requested that the applicant provide information of the effect on aging if hydrazine concentrations were to increase above the normal operating range in the EPRI guideline during the period of extended operation.
| |
| In its response dated January 13, 2011, the applicant added Commitment 56 to LRA Appendix A, to revise the program documents to reflect the EPRI guideline operating ranges and action level values for hydrazine. Consequently, the applicant deleted Exception 2 from this AMP in the LRA, since an exception was not being taken. The applicant also stated that it evaluated the significance of allowing the system to operate with the higher hydrazine levels and determined it to be acceptable. Similarly, the applicant stated that it routinely monitored the operation during elevated ranges, and there were no indications of system or component degradation. In its review of this response, the staff did not consider that there was sufficient information regarding how the monitoring during elevated hydrazine levels had determined there were minimal long
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| -term aging effects of copper components in the thermal barrier system.
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| By letter dated March 7, 2011, the staff issued RAI B.2.1.12
| |
| -8, requesting that the applicant provide the technical information that describes why the elevated levels of hydrazine will not have caused accelerated aging of the components in the thermal barrier system that could affect component functions during the period of extended operation. The applicant was also asked to provide information on the AMP that will be used to manage the accelerated aging if it is determined that the elevated levels of hydrazine may have caused accelerated aging.
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| In its response, dated April 5, 2011, the applicant stated the higher sulfate and hydrazine levels were not expected to increase the corrosion rate of any copper alloys because the thermal barrier system is an all
| |
| -ferrous design. The applicant stated that the increased level of hydrazine and sulfate would not lead to an increased corrosion rate for either stainless steel or carbon steels because the higher level of hydrazine would lead to a low oxygen concentration and low electrochemical potential for stainless steel components. The staff finds this response acceptable because the applicant clarified that there are no copper components that could have an increased corrosion rate due to the higher level of ammonia. In addition, the staff noted that the higher levels of hydrazine will decrease the concentration of oxygen, which will lead to a decreased corrosion rate for carbon alloys. The staff further noted that a lower oxygen level will also reduce the electrochemical potential of any stainless steel components, which will reduce the likelihood of SCC even at the higher levels of sulfate for the temperature normally observed in the thermal barrier system. The staff's concern described in RAIs B.2.1.12
| |
| -1 and B.2.1.12
| |
| -8 is resolved.
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| | |
| Aging Management Review Results 3-84 Exception 3. LRA Section B.2.1.12 states an exception to the "preventive actions" and "monitoring and trending" program elements. The applicant stated that the EPRI guideline specifies Action Level 1 for sulfates as a concentration greater than 150 ppb. The applicant further stated that the thermal barrier cooling water system has an Action Level 1 of 500 ppb.
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| The staff reviewed this exception to the GALL Report and noted that the applicant took the exception regarding the higher limit to the sulfate operating range because the previous EPRI guideline did not specify this value. The applicant further stated that it evaluated the significance of operating the system at the higher concentration level and determined it to be acceptable because of lower oxygen levels, alkaline pH, and absence of sulfides in the thermal barrier cooling water system. However, the applicant's technical basis documents did not justify why it is appropriate to have higher sulfate levels in its thermal barrier system than is recommended by the EPRI guideline. By letter dated December 14, 2010, the staff issued RAI B.2.1.12-1, requesting that the applicant justify the higher sulfate levels in the thermal barrier system compared to those recommended in the EPRI guideline, and to discuss why these higher levels will not lead to enhanced degradation. In addition, the staff requested that the applicant provide information for the effects on aging if sulfate concentrations were increased above the action level in the EPRI guideline during the period of extended operation.
| |
| In its response dated January 13, 2011, the applicant added Commitment 56 to LRA Appendix A, to revise the program documents to reflect the EPRI guideline operating ranges and action level values for sulfates. Consequently, the applicant deleted Exception 3 to this AMP in the LRA, since an exception was no longer being taken.
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| The evaluation of the potential for elevated sulfate levels in the past to have accelerated aging effects was included in RAIs B.2.1.12-1 and B.2.1.12
| |
| -8, and the staff's findings are discussed above in the evaluation for Exception 2.
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| Exception 4. LRA Section B.2.1.12 states an exception to the "parameters monitored or inspected" and "monitoring and trending" program elements. The applicant stated that the EPRI guideline indicates that hydrazine concentrations and pH should be monitored weekly. In contrast, the applicant stated that, for the thermal barrier cooling water system, it would monitor hydrazine and pH monthly to reduce worker radiation exposure. The applicant further stated that recent system data trends show that hydrazine concentration and pH remained stable between the monthly samples, which demonstrates that monthly monitoring frequency is sufficient.
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| The staff reviewed this exception to the GALL Report and noted that the applicant took the exception because the thermal barrier cooling water system is located inside containment, and monitoring monthly would reduce the radiation exposure. The staff reviewed the hydrazine and pH data trends during the audit, which showed that these parameters are stable and predictable. The staff finds this program exception acceptable because the hydrazine data trends indicate that a monthly measurement rate is frequent enough to maintain the hydrazine within acceptable bounds.
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| Exception 5. LRA Section B.2.1.12 states an exception to the "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements. The applicant stated that it does not rely on performance and functional testing to verify the effectiveness of chemistry controls and managing aging effects, as stated in the GALL Report. Instead, the applicant stated that it monitors program effectiveness through Aging Management Review Results 3-85 internal inspections of opportunity and through corrosion monitoring by trending normal plant periodic samples and by evaluating system corrosion coupons.
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| The staff reviewed this exception to the GALL Report and noted that the applicant took the exception because it considered the performance and functional testing to fall under the maintenance rule. However, it was not clear to the staff whether the applicant was crediting maintenance rule activities to manage aging effects in the closed
| |
| -cycle cooling water system during the period of extended operation and, if so, how these activities are captured in an AMP. By letter dated December 14, 2010, the staff issued RAI B.2.1.12
| |
| -3, requesting that the applicant explain how the maintenance rule activities are included in the aging management of the closed
| |
| -cycle cooling water systems during the period of extended operation.
| |
| In its response dated January 13, 2011, the applicant stated that the maintenance rule activities are not being credited to manage aging effects in the closed
| |
| -cycle cooling water system during the period of extended operation. The applicant stated that it modified its program to remove the reference to the maintenance rule and that the performance monitoring is part of the engineering program that verifies the component active functions. The staff finds this response acceptable because the applicant modified its program to remove documentation that reports that the maintenance rule is part of the activities for managing aging in the closed
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| -cycle cooling water systems. The staff's concern described in RAI B.2.1.12
| |
| -3 is resolved.
| |
| The staff also examined the use of corrosion coupons, and it was not clear from the basis documents that the corrosion coupons would be placed in a condition representative of the most detrimental environment for a given closed
| |
| -cycle system (highest temperature, stagnant conditions, etc.). In addition, it was not clear if the corrosion coupons would be stressed, which is necessary to evaluate SCC. By letter dated December 14, 2010, the staff issued RAI B.2.1.12-5, requesting justification on how the corrosion coupons will represent highly susceptible material and environmental conditions observed in a closed
| |
| -cycle cooling water system. The applicant was also asked to provide additional information on why the corrosion coupons are adequate to evaluate SCC susceptibility.
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| In its response dated January 13, 2011, the applicant stated corrosion coupon monitoring will be used to assess the effectives of the corrosion inhibitors by quantifying the corrosion rates of the coupons. The applicant stated that the current location in the coupons in the closed
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| -cycle cooling water system is appropriate for monitoring the effectiveness of corrosion inhibitors. The applicant further stated that the corrosion coupons are not pre
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| -stressed and are not used for monitoring SCC. The applicant stated that SCC will be evaluated by conducting visual inspection of individual components for evidence of pitting, general corrosion film presence, biological activities, deposits, and SCC. The staff finds the response and program exception acceptable because the applicant has modified the program to indicate that SCC will be managed by visual inspections, and the corrosion coupons are placed in the appropriate locations to evaluate the effectiveness of corrosion inhibitors. The staff's concern described in RAI B.2.1.12-5 is resolved.
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| Enhancement 1. LRA Section B.2.1.12 states an enhancement to the "detection of aging effects" program element. The applicant stated that the program will be enhanced to include visual inspections for cracking, loss of material, and fouling in the primary component cooling water system, thermal barrier cooling water system, diesel generator jacket water cooling system, fire water pump diesel engine coolant system, and control building air handling coolant system.
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| Aging Management Review Results 3-86 The staff reviewed this enhancement against the corresponding program element in GALL Report AMP XI.M21. The staff noted that the GALL Report AMP states that the extent and schedule of inspections and testing should ensure detection of corrosion or SCC before the loss of the intended function of the component. The staff finds the applicant's enhancement acceptable because it provides an alternative technique to verify the effectiveness of the control of water chemistry to manage aging in the closed
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| -cycle cooling water systems.
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| Based on its audit, review of the application, and review of the applicant's responses to RAIs B.2.1.12
| |
| -1, B.2.1.12
| |
| -2, B.2.1.12
| |
| -3, B.2.1.12
| |
| -4, B.2.1.12
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| -5, B.2.1.12
| |
| -7, B.2.1.12
| |
| -8, and B.2.1.12-9, the staff finds that elements one through six of the applicant's Closed
| |
| -Cycle Cooling Water System Program, with acceptable exceptions and an enhancement, are consistent with the corresponding program elements of GALL Report AMP XI.M21 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.12 summarizes operating experience related to the Closed-Cycle Cooling Water System Program. The applicant stated that, in 2003, the chemistry department found that the hydrazine consumption in the thermal barrier cooling water system had significantly increased since the fall of 2000. The applicant stated that an investigation identified potential air entrapment in the thermal barrier cooling water system. The applicant stated that it statically and dynamically vented the thermal barrier cooling water system, which resolved the issue. In addition to this one operating experience, the applicant stated that, in 2003, it reviewed industry operating experience about an issue with cracking of brass bolting in the diesel generator jacket water cooling system. The applicant further stated that this evaluation showed that Seabrook uses a glycol mixture, which is similar in constituents to the industry operating experience conditions but that Seabrook uses a much higher concentration. The applicant stated that this evaluation concluded that Seabrook's tolytriazole dosage levels are sufficient to minimize brass degradation. The applicant also stated that this evaluation shows it uses industry experience to challenge existing program practices and validates existing program procedures through experiences or standards applied at other nuclear power plants.
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| The staff reviewed operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program. During its review, the staff identified operating experience that could indicate that the applicant's program may not be effective in adequately managing aging effects during the period of extended operation. The staff determined the need for additional clarification, which resulted in the issuance of an RAI.
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| In LRA Section B.2.1.12, the applicant stated that it had addressed operating experience related to the closed
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| -cycle cooling water systems. However, the staff found that the applicant had not addressed a recurring condition in the primary component cooling water system, where loss of material downstream of valves was causing cavitation erosion from throttling. The applicant stated that it had conducted flow rebalancing to alleviate the concern. However, it was unclear to the staff how the applicant has re
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| -evaluated these areas after flow rebalancing was conducted to determine whether loss of material due to cavitation erosion remains an issue in the primary component cooling water system. By letter dated December 14, 2010, the staff Aging Management Review Results 3-87 issued RAI B.2.1.12
| |
| -6, requesting that the applicant provide additional information on how the loss of material due to cavitation erosion was confirmed to have been eliminated (e.g., inspection). If loss of material for this mechanism is still an applicable aging issue, the applicant was asked to provide information on how this aging effect is being managed.
| |
| In its response dated January 13, 2011, the applicant stated that it will conduct an inspection for loss of material prior to entering the period of extended operation. The applicant stated that the inspection will be performed during the 10
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| -year period prior to the period of extended operation. The staff finds this response acceptable because the applicant will conduct an inspection to determine if the flow rebalancing has eliminated the cavitation
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| -induced wear. However, the staff considers that these activities should be captured in a commitment, and during a teleconference on April 10, 2012, the applicant agreed to revise its response to RAI B.2.1.12
| |
| -6. By letter dated April 26, 2012, the applicant added a new commitment (Commitment 70) to inspect the piping downstream of valves CC
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| -V-444 and CC
| |
| -V-446 within 10 years prior to the period of extended operation to determine whether the loss of material due to cavitation
| |
| -induced erosion has been eliminated. The staff's concern described in RAI B.2.1.12
| |
| -6 is resolved.
| |
| Based on its audit and review of the application, and review of the applicant's response to RAI B.2.1.12-6, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking appropriate corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.12 provides the UFSAR supplement for the Closed
| |
| -Cycle Cooling Water System Program. The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Tables 3.1
| |
| -2, 3.2-2, 3.3-2, and 3.4
| |
| -2. The staff also notes that the applicant committed (Commitment Nos. 2, 56, 57, and 70) to enhancing and revising the Closed
| |
| -Cycle Cooling Water System Program prior to entering the period of extended operation. Specifically, the applicant committed to enhancing the program to include visual inspection for cracking, loss of material, and fouling when the in
| |
| -scope systems are opened for maintenance; to revise program documents to reflect EPRI Guideline operating ranges and action levels for hydrazine, sulfates, and diesel generator cooling water jacket pH; and to confirm that loss of material due to cavitation erosion has been eliminated in the system. The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its audit and review of the applicant's Closed
| |
| -Cycle Cooling Water System Program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exceptions and their justifications and determined that the AMP, with the exceptions, is adequate to manage the aging effects for which the LRA credits it. Also, the staff reviewed the enhancement and confirmed that its implementation through Commitment Nos. 2, 56, 57, and 70 prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended Aging Management Review Results 3-88 function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.5 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program Summary of Technical Information in the Application. LRA Section B.2.1.13 describes the existing Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program as consistent, with enhancements, with GALL Report AMP XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems." The applicant stated that the program manages the aging effects of loss of material due to general corrosion on structural steel members, components, and rails of the in
| |
| -scope cranes and the aging effects of loss of material due to wear on the rails in the rail system. The applicant also stated that the program conducts visual inspections to identify aging effects prior to loss of function in accordance with its Lifting System Manual. The applicant further stat ed that these inspections are conducted yearly and documented on work orders.
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| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.M23. As discussed in the audit report, the staff confirmed that these elements are consistent with the corresponding elements of GALL Report AMP XI.M23. The staff also reviewed the portions of the "scope of program," "parameters monitored or inspected," and "detection of aging effects" program elements associated with the enhancements to determine if the program will be adequate to manage the aging effects for which it is credited. The staff's evaluation of these enhancements follows.
| |
| Enhancement 1. LRA Section B.2.1.13 states an enhancement to the "scope of program" and "parameters monitored or inspected" program elements. The LRA states that the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program's Lifting System Manual will be enhanced to include monitoring of general corrosion on the crane and trolley structural components and the effects of wear on the rails in the rail system.
| |
| The staff reviewed this enhancement against the corresponding program elements in GALL Report AMP XI.M23 and noted that GALL Report AMP XI.M23 recommends that the program manage general corrosion on the crane and trolley structural components and the effects of wear on the rails in the rail system. The staff finds the program enhancement acceptable because, when implemented, the program elements will be consistent with the recommendations in GALL Report AMP XI.M23.
| |
| Enhancemen t 2. LRA Section B.2.1.13 states an enhancement to the "scope of program" and "detection of aging effects" program elements. The LRA states that the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program's Lifting System Manual will be enhanced to list additional cranes related to the refueling handling system.
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| | |
| Aging Management Review Results 3-89 The staff reviewed this enhancement against the corresponding program elements in GALL Report AMP XI.M23. During the audit, the staff reviewed the applicant's AMP basis document for the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program and noted that the Lifting System Manual will be enhanced to list all in
| |
| -scope cranes for periodic inspections. This enhancement will ensure that the effects of aging will be managed, consistent with the CLB, for the period of extended operation. The staff finds the program enhancement acceptable because, when implemented, the program elements will be consistent with the recommendations in GALL Report AMP XI.M23.
| |
| Based on its audit and review of the application, the staff finds that elements one through six of the applicant's Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program, with acceptable enhancements, are consistent with the corresponding program elements of GALL Report AMP XI.M23 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.13 summarizes operating experience related to the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program. The applicant stated that there has been no history of corrosion
| |
| -related degradation that has impaired cranes, and preventive maintenance work orders are used for tracking, identifying, and maintaining crane structural components of lifting systems and crane rail systems. During the audit, the staff reviewed an operating experience example described in a condition report, indicating that the bus work track of the filter cask monorail hoist system was severely pitted from excessive corrosion. The staff reviewed the applicant's inspection findings and found that, during the inspection, corrosion was not observed on the rails and structural components of the system, which are the portions of the system within the scope of this program. The applicant initiated a preventive maintenance work order, conducted a root cause analysis, and replaced the bus track with a corrosion
| |
| -resistant material, thus demonstrating proper management and implementation of the program.
| |
| The staff reviewed operating experience information during the audit to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the audit report, the staff conducted an independent search of plant operating experience to determine if the applicant adequately incorporated and evaluated operating experience related to this program.
| |
| During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.13 provides the UFSAR supplement for the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program.
| |
| | |
| Aging Management Review Results 3-90 The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Table 3.3-2. The staff also noted that the applicant committed (Commitment Nos. 3 and 4) to enhancing the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program prior to entering the period of extended operation. Specifically, the applicant committed to enhancing the program to monitor general corrosion on the crane and trolley structural components and the effects of wear on the rails in the rail system and to enhancing the program to list additional cranes for monitoring. The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its audit and review of the applicant's Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program, the staff determined that those program elements for which the applicant claimed consistency with t he GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that their implementation through Commitment Nos. 3 and 4 prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it was compared. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.2.6 Compressed Air Monitoring Program Summary of Technical Information in the Application. LRA Section B.2.1.14 describes the existing Compressed Air Monitoring Program as consistent, with an enhancement, with GALL Report AMP XI.M24, "Compressed Air Monitoring." The applicant stated that the program manages the aging effects of hardening and loss of strength due to elastomer degradation; loss of material due to crevice, general, galvanic, and pitting corrosion; and reduction of heat transfer due to fouling of the plant compressed air system components. The applicant also stated that the program includes continuous dew point measurements, and sampling for other contaminants in the compressed air system is conducted on an annual basis.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.M24. As discussed in the audit report, the staff confirmed that each element of the applicant's program is consistent with the corresponding element of GALL Report AMP XI.M24, with the exception of the "parameters monitored or inspected" program element. For this element, the staff determined the need for additional clarification, which resulted in the issuance of an RAI.
| |
| GALL Report AMP XI.M24 states that the program's inspections need to ensure that the intended function of the air system is maintained under the "parameters monitored or Aging Management Review Results 3-91 inspected" program element description. The applicant's AMP states that the program specifies inspections to be conducted in accordance with the New Hampshire State inspectio n requirements; however, the program does not clarify the extent of the inspection or explain whether they are adequate to ensure that the intended function of the compressed air system is maintained. By letter dated November 18, 2010, the staff issued RAI B.2.1.14
| |
| -1, requesting that the applicant provide information on how the in
| |
| -scope components in the compressed air system will be inspected, consistent with the recommendations defined in GALL Report AMP XI.M24. In its response dated December 17, 2010, the applicant stated that the program description will explicitly include that visual inspections are to be performed during routine maintenance procedures, and opportunistic inspections will be performed to identify instances of corrosion and the presence of contaminants in the compressed air system, containment compressed air system, and diesel generator compressed air system. Furthermore, the applicant removed the reference to the State of New Hampshire air receiver tank inspection, which is not relied on to meet the recommendations of GALL Report AMP XI.M24. The in
| |
| -scope components were tabulated in the applicant's response and are found by the staff to be comprehensive.
| |
| The staff finds the applicant's response acceptable because the program description was modified to explicitly state adherence to the GALL Report recommendations. The staff's concern described in RAI B.2.1.14
| |
| -1 is resolved.
| |
| The staff also reviewed the portions of the "scope of program," "preventive actions," "parameters monitored or inspected," "detection of aging effects," and "acceptance criteria" program elements associated with the enhancement to determine if the program will be adequate to manage the aging effects for which it is credited. The staff's evaluation of this enhancement follows.
| |
| Enhancement 1. LRA Section B.2.1.14 states an enhancement to the "scope of program,"
| |
| "preventive actions," "parameters monitored or inspected," "detection of aging effects," and "acceptance criteria" program elements. The applicant stated that annual air quality testing for particulate content and volatile oil will be conducted to ensure compliance with air quality standards.
| |
| The staff reviewed this enhancement against the corresponding program elements in GALL Report AMP XI.M24. The staff noted that the applicant's program appropriately addresses the detection of aging effect by combined air monitoring method so that compressed air quality is confirmed, and corrective actions can be initiated if indicated. The staff finds the applicant's enhancement acceptable because, when conducted in addition to the continuous moisture monitoring of the compressed air system, the annual air quality testing provides adequate monitoring of compressed air quality.
| |
| Based on its audit, review of the application, and review of the applicant's response to RAI B.2.1.14
| |
| -1, the staff finds that elements one through six of the applicant's Compressed Air Monitoring Program, with an acceptable enhancement, are consistent with the corresponding program elements of GALL Report AMP XI.M24 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.14 summarizes operating experience related to the Compressed Air Monitoring Program. The applicant stated that actions were taken in response to detected rust in an air compressor. The applicant described the detection as being part of an Aging Management Review Results 3-92 inspection during a repair of the subject compressor. The affected components were replaced, and the engineering analysis led to procedure modifications that isolate susceptible down-stream components from potentially reduced quality compressed air during compressor shutdowns.
| |
| The applicant also stated that a minor secondary plant transient occurred due to an air leak in the tubing to a heater drain system level control valve. A material change from copper to stainless steel for smaller instrument lines was conducted to remove the material that was determined to be more susceptible to leakage, and inspections were conducted of critical air
| |
| -operated valves in high
| |
| -risk systems to evaluate the condition of similar component and material combinations.
| |
| The staff reviewed operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program.
| |
| During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation. Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.14 provides the UFSAR supplement for the Compressed Air Monitoring Program. The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Table 3.3
| |
| -2. The staff also noted that the applicant committed (Commitment 5) to enhancing the Compressed Air Monitoring Program prior to entering the period of extended operation. Specifically, the applicant committed to conducting annual air quality testing for particulate content and volatile oil. In addition, the applicant committed (Commitment 61) to replacing the flexible hoses associated with the diesel generator air compressor on a frequency of every 10 years, beginning within 10 years prior to entering the period of extended operation.
| |
| The staff determined that the information in the UFSAR supplement, as amended, is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its audit and review of the applicant's Compressed Air Monitoring Program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent. Also, the staff reviewed the enhancement and confirmed that its implementation through Commitments 5 and 61 prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to Aging Management Review Results 3-93 which it was compared. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.2.7 Fire Protection Program Summary of Technical Information in the Application. LRA Section B.2.1.15 describes the existing Fire Protection Program as consistent, with enhancements, with GALL Report AMP XI.M26, "Fire Protection." The applicant stated that the Fire Protection Program manages aging of penetration seals, fire barrier walls, ceilings, floors, and all fire
| |
| -rated doors that perform a fire barrier function, as well as the aging effects on the intended function of the fuel supply line to the diesel fire pumps. The applicant also stated that the program conducts detailed inspections and tests in accordance with its surveillance test procedures, including regular inspections of fire barriers, penetration seals, and fire
| |
| -rated doors, and performance tests and flushes on fire pumps. The applicant further stated that it does not use a CO 2 fire suppression system, and the halon fire suppression system is used in a nonsafety
| |
| -related computer room in the control building; therefore, it is not within the scope of license renewal.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated. The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.M26. As discussed in the audit report, the staff confirmed that these elements are consistent with the corresponding elements of GALL Report AMP XI.M26.
| |
| The staff also reviewed the portions of the "parameters monitored or inspected" and "detection of aging effects" program elements associated with the enhancements to determine if the program will be adequate to manage the aging effects for which it is credited. The staff's evaluation of these enhancements follows.
| |
| Enhancement 1. LRA Section B.2.1.15 states an enhancement to the "detection of aging effects" program element. The LRA states that the Fire Protection Program implementing documents will be enhanced to include visual inspection of penetration seals by a fire protection qualified inspector.
| |
| The staff reviewed this enhancement against the corresponding program element in GALL Report AMP XI.M26 and noted that the GALL Report recommends that penetration seals be visually inspected by fire protection qualified inspectors. The staff finds the program enhancement acceptable because, when implemented, the program element will be consistent with the recommendations in GALL Report AMP XI.M26.
| |
| Enhancement 2. LRA Section B.2.1.15 states an enhancement to the "parameters monitored or inspected" and "detection of aging effects" program elements. The LRA states that the Fire Protection Program implementing documents will be enhanced to include additional age
| |
| -related degradation inspection criteria such as spalling and loss of material caused by freeze
| |
| -thaw, chemical attack, and reaction with aggregates. This enhancement will also include visual inspection of fire
| |
| -rated exposed barrier walls, floors, and ceilings by a fire protection qualified inspector.
| |
| | |
| Aging Management Review Results 3-94 The staff reviewed this enhancement against the corresponding program elements in GALL Report AMP XI.M26 and noted that the GALL Report recommends that fire barrier walls, ceilings, and floors be visually inspected for cracking, spalling, and loss of material caused by freeze-thaw, chemical attack, and reaction with aggregates and that those inspections be performed by a fire protection qualified inspector. The staff finds the program enhancement acceptable because, when implemented, the program element will be consistent with the recommendations in GALL Report AMP XI.M26.
| |
| Enhancement 3. LRA Section B.2.1.15 states an enhancement to the "detection of aging effects" program element. The LRA states that the Fire Protection Program implementing documents will be enhanced to include visual inspection of fire
| |
| -rated doors by a fire protection qualified inspector.
| |
| The staff reviewed this enhancement against the corresponding program element in GALL Report AMP XI.M26 and noted that the GALL Report recommends that fire
| |
| -rated doors be visually inspected by fire protection qualified inspectors. The staff finds the program enhancement acceptable because, when implemented, the program element will be consistent with the recommendations in GALL Report AMP XI.M26.
| |
| Based on its audit and review of the application, the staff finds that elements one through six of the applicant's Fire Protection Program, with acceptable enhancements, are consistent with the corresponding program elements of GALL Report AMP XI.M26 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.15 summarizes operating experience related to the Fire Protection Program. The applicant stated that leakage was identified on the diesel fire pump casing vent during the surveillance testing in September 2002, and it took appropriate corrective actions and repaired the leak using a preventive maintenance work order. The applicant also stated that it identified two degraded fire barriers in October 2002, and work orders were issued to repair the two barriers. The applicant further stated that it identified a broken fire
| |
| -door handle in April 2003, and it repaired and retested the door by issuing a work order, which demonstrates that the Fire Protection Program satisfactorily identifies deficiencies.
| |
| The staff reviewed operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program. During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the effects of aging on SSCs within the scope of the program, and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.15 provides the UFSAR supplement for the Fire Protection Program. The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program as Aging Management Review Results 3-95 described in SRP
| |
| -LR Table 3.3
| |
| -2. The staff also noted that the applicant committed (Commitment Nos. 6, 7, and 8) to enhancing the Fire Protection Program prior to the period of extended operation. Specifically, the applicant committed to enhancing the program to do the following:
| |
| * include the performance of visual inspections of penetration seals by a fire protection qualified inspector
| |
| * add inspection requirements such as spalling, loss of material caused by freeze
| |
| -thaw, chemical attack, and reaction with aggregates
| |
| * include the performance of visual inspections of fire
| |
| -rated doors by a fire protection qualified inspector The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its audit and review of the applicant's Fire Protection Program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the enhancements and their justifications and confirmed that their implementation through Commitment Nos. 6, 7, and 8 prior to the period of extended operation would make the existing program consistent with the GALL Report AMP to which it was compared. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.2.8 Fire Water System Program Summary of Technical Information in the Application. As amended by letters dated March 5, 2014, March 9, 2015, and May 19, 2015, LRA Section B.2.1.16 describes the existing Fire Water System Program as consistent, with enhancements, with GALL Report AMP XI.M27, "Fire Water System," as modified by LR
| |
| -ISG-2012-02, "Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation." The applicant stated that this program manages the following:
| |
| * loss of material due to general, pitting, crevice, galvanic, and microbiologically
| |
| -influenced corrosion
| |
| * fouling Aging Management Review Results
| |
| * 3-96 reduction of heat transfer due to fouling for fire water system components using detailed inspections in accordance with station surveillance test procedures The applicant also stated that the structures, systems, and components included within the scope of this program include both fire suppression and fire mitigation components. The applicant further stated that the program includes regular inspections, periodic flushing, chemical additions, and performance testing, which are conducted to ensure no corrosion, microbiologically
| |
| -influenced corrosion, or biofouling has occurred.
| |
| Subsequent to the submittal of the LRA, the staff issued LR
| |
| -ISG-2012-02, which revised several AMPs, including the guidance for AMP XI.M27, "Fire Water System." By letters dated March 5, 2014; March 9, 2015; and May 19, 2015, the applicant revised the Fire Water System Program to address changes in the recommendations stated in LR
| |
| -ISG-2012-02 AMP XI.M27.
| |
| In addition, based on reviews of LRAs and industry operating experience, the staff identified an issue concerning loss of coating integrity of internal coatings of piping, piping components, heat exchangers, and tanks. By letters dated March 5, 2014; March 9, 2015; and May 19, 2015, the applicant revised the Fire Water System Program to address loss of coating integrity for metallic components with internal coatings. The staff's evaluation of the changes associated with coating integrity is documented in SER Section 3.0.3.4.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated. The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.M27. As discussed in the audit report, the staff confirmed that each element of the applicant's program is consistent with the corresponding elements of GALL Report AMP XI.M27. The staff's evaluation of the changes in the March 5, 2014; March 9, 2015; and May 19, 2015, letters follows. The applicant provided a brief summary of how it will meet each of the inspections and tests listed in LR
| |
| -ISG-2012-02 AMP XI.M27 Table 4a, "Fire Water System Inspection and Testing Recommendations," hereinafter referred to as "Table 4a." Based on its review, the staff finds that, with the following clarifications and RAIs, the applicant's proposed inspections and tests are consistent with Table 4a.
| |
| * The staff noted that, in regard to standpipe and hose station flow tests, the applicant stated that, "[w]here a flow test of the hydraulically most remote outlet(s) is not practical, Nuclear Service Organization/Nuclear Electric Insurance Limited (NSO/NEIL) needs to be consulted while determining the appropriate location for the test. A flow test needs to be conducted every 5 years." The staff also noted that NFPA 25, "Standard for the Inspection, Testing, and Maintenance of Water
| |
| -Based Fire Protection Systems," Section 6.3.1.2, states that, "[w]here a flow test of the hydraulically most remote outlet(s) is not practical, the authority having jurisdiction shall be consulted for the appropriate location for the test." NFPA 25, Section 3.2.2, defines the "Authority Having Jurisdiction" (AHJ) as, "An organization, office, or individual responsible for enforcing the requirements of a code or standard, or for approving equipment, materials, an Aging Management Review Results
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| * 3-97 installation, or a procedure." Although NSO/NEIL is not the AHJ, the staff considers the applicant's proposal consistent with LR
| |
| -ISG-2012-02 AMP XI.M27 because an independent body with expertise in fire water systems will be consulted while the applicant is determining the appropriate location for the test.
| |
| The applicant stated that, "[a] 3
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| -year flow test is conducted for flow verification of the fire protection water system on a sufficient number of hydrants to determine the capacity of the system in the area tested." Based on the statement, "capacity of the system in the area tested," it is not clear to the staff that the underground piping system is tested to the worst-case design flow conditions. It is also not clear to the staff that the flow rates during the tests will be consistent enough to be able to trend the friction loss characteristics of the underground piping system. By letter dated November 18, 2014, the staff issued RAI B.2.1.16
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| -4, requesting that the applicant state whether the underground piping system will be tested to the worst
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| -case design flow conditions and the basis for why the flow rates during the tests are consistent enough to be able to trend the friction loss characteristics of the underground piping system.
| |
| In its reply dated March 9, 2015, the applicant stated:
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| A 3 year flow test is conducted for flow verification of the fire protection water system. This flow test was developed in accordance with NFPA Handbook, 14th Edition, Chapter 5, Section 11. The NFPA handbook states, "the usual procedure for conducting a flow test on a water system is to take Pitot readings on a sufficient number of hydrants to determine the capacity of the system in the area tested." This is consistent with the Seabrook procedure. The acceptance criteria in the procedure is based on the baseline data. The baseline data initially met the acceptance testing of the system which was based on design. Testing since then has consistently met and exceeded the acceptance criteria and demonstrates compliance with NFPA 25 (2011 Edition), Section 7.3.
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| The staff does not agree with the applicant's response in regard to using NFPA Handbook, 14th Edition, Chapter 5, Section 11, as guidance for its basis for the acceptability of the underground flow tests. NFPA 25, Section 7.3.1.1, states that, "[f]low tests shall be made at flows representative of those expected during a fire, for the purpose of comparing the friction loss characteristics of the pipe with those expected for the particular type of pipe involved, with due consideration given to the age of the pipe and to the results of previous flow tests." The Water
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| -Based Fire Protection Systems Handbook, Fourth Edition, states that the flows expected during a fire are not just those used by automatic suppression systems but also include much higher flows that take into consideration manual fire
| |
| -fighting tactics. It is not clear to the staff that the applicant's statement, "the capacity of the system in the area tested" satisfies this statement. The staff recognizes that, for flow testing purposes, it is only reasonably possible to initiate flow through hydrants; notwithstanding, it is not clear whether this flow is representative of the flow that would be expected from initiation of fire sprinklers and expected manual fire
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| -fighting tactics. NFPA 25, Section 7.3.1.3, states that , "[w]here underground piping supplies individual fire sprinkler, standpipe, water spray, or foam-water sprinkler systems and there are no means to conduct full flow tests, tests Aging Management Review Results
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| * 3-98 generating the maximum available flows shall be permitted." The staff noted that, based on a review of the license renewal drawings; there are multiple fire sprinkler standpipes in the fire water system. NFPA 25, Section 7.3.1.3, establishes the acceptability of using "the capacity of the system in the area tested" as being acceptable for trending underground flow tests. The staff finds the applicant's response acceptable because NFPA 25 recognizes that lower flow rates can be acceptable for trending purposes and the flow test results are consistently compared to acceptance criteria in the area that is tested. The staff's concern described in RAI B.2.1.16
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| -4 is resolved.
| |
| The applicant stated that internal inspections will be conducted on the fire protection water storage tanks (FWST) every 5 years. It is not clear to the staff whether the additional tests and inspections cited in NFPA 25, Section 9.2.7, will be conducted. By letter dated November 18, 2014, the staff issued RAI B.2.1.16
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| -5, requesting that the applicant state whether the additional tests and inspections specified in NFPA 25, Section 9.2.7, will be conducted.
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| In its reply dated March 9, 2015, the applicant stated that it will conduct the additional inspections and tests cited in NFPA 25 (2011 Edition), Section 9.2.7, when required by NFPA 25, Section 9.2.6.4. The applicant revised its program to include a new enhancement, Enhancement 10, and Commitment 85 to implement this change.
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| The staff finds the applicant's response acceptable because the applicant has committed to perform the additional inspections and tests cited in NFPA 25, Section 9.2.7. These tests and inspections can ensure that the extent of potentially degraded coatings and loss of material will be detected. The staff's concern described in RAI B.2.1.16
| |
| -5 is resolved.
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| * The applicant stated that "[w]ater spray fixed systems strainers are cleaned every 5 years during the wet sprinkler alarm valve inspection/maintenance, deluge or sprinkler flooding valve inspection/maintenance, and deluge or sprinkler multimatic valve inspection/maintenance." The staff also noted that NFPA 25, Section 10.2.1.7, allows mainline strainer inspections to be conducted every 5 years. It is not clear to the staff whether the term "inspection" in the applicant's revised program means a flow test or a visual inspection of some nature and whether "maintenance" means any opening of the system such that the strainers are accessible. By letter dated November 18, 2014, the staff issued RAI B.2.1.16
| |
| -6, requesting that the applicant state whether the term "inspection" includes flow tests and "maintenance" means any opening of the system such that the strainers are accessible.
| |
| In its reply dated March 9, 2015, the applicant stated that the terms "inspection" and "maintenance" include disassembly and cleaning of the strainer basket and body. Flow tests are not conducted. The applicant also stated that mainline strainers are installed upstream of the deluge/preaction sprinkler trim piping strainers. The applicant revised its program to include a new enhancement, Enhancement 11, and Commitment 86 to include disassembly, inspection, and cleaning of these mainline strainers. The applicant stated that potable water from the town of Seabrook is the source of water for the fire water system and, as a result, conducting the strainer inspections every five years is adequate.
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| | |
| Aging Management Review Results
| |
| * 3-99 The staff finds the applicant's response acceptable because: (a) strainer inspections and maintenance include disassembly and cleaning of the strainer basket and body, which are capable of detecting corrosion products and debris that could lead to flow blockage in the fire water system, (b) using potable water as a water source for the fire water system provides reasonable assurance that conducting inspections every five years will be adequate to detect potential flow blockage because the water is less likely to contain obstructive material, (c) conducting inspections every 5 years is consistent with NFPA 25, Section 10.2.1.7, and (d) the open head spray nozzle air flow tests described below in the response to RAI B.2.1.16
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| -7 provide insight into the internal condition of the fire water piping system deluge spray and preaction system on a refueling outage interval. The staff's concern described in RAI B.2.1.16
| |
| -6 is resolved.
| |
| The applicant stated that "[a]n Open Head Spray Nozzle Air Flow Test is performed every 3 years to verify that the open heads and branch lines on the deluge system are free of debris and not blocked. This is done by connecting the selected deluge system to the service air system and observing air flow through each sprinkler head." The staff noted that NFPA 25, Section 13.4.3.2.2.4, allows deluge valve flow test frequencies to not exceed 3 years; however, LR
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| -ISG-2012-02 AMP XI.M27 Table 4a states that water spray fixed system operational tests should be conducted on a refueling outage interval.
| |
| By letter dated November 18, 2014, the staff issued RAI B.2.1.16
| |
| -7, requesting that the applicant state the basis for conducting deluge valve flow testing every 3 years instead of on a refueling outage interval.
| |
| In its reply dated March 9, 2015, the applicant stated the Open Head Spray Nozzle Air Flow Test will be conducted every refueling outage instead of once every 3 years. The applicant revised its program to include a new enhancement, Enhancement 12, and Commitment 87 to cite the revised frequency of this testing.
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| The staff finds the applicant's response acceptable because the frequency of testing will be consistent with LR
| |
| -ISG-2012-02 AMP XI.M27. The staff's concern described in RAI B.2.1.16
| |
| -7 is resolved.
| |
| * The applicant stated that the program "will be enhanced to conduct an inspection of piping and branch line conditions every 5 years by opening a flushing connection at the end of one main and by removing a sprinkler toward the end of one branch line for the purpose of inspecting for the presence of foreign organic and inorganic material." The staff noted that NFPA 25 Section 14.2.2 specifies that, on an alternating schedule, an internal inspection of every other wet pipe system in buildings with multiple wet pipe systems should be conducted every 5 years. By letter dated November 18, 2014, the staff issued RAI B.2.1.16
| |
| -8 requesting that the applicant confirm whether or not there are multiple wet pipe systems in any of the structures containing in
| |
| -scope fire water systems and if there are, state the basis for why testing is not conducted on every other system every 5 years.
| |
| In its reply dated March 9, 2015, the applicant stated that, "[t]here are no multiple wet pipe systems in any of the structures containing in
| |
| -scope fire water systems."
| |
| | |
| Aging Management Review Results
| |
| * 3-100 The staff noted that license renewal drawing 1
| |
| -FP-LR20270, "Fire Protection Turbine Building Detail sheet 2 of 2," shows multiple sprinkler zones. License renewal drawing 1-FP-LR20272, "Fire Protection Valve Details," shows that each of these sprinkler zones has an individual alarm valve configuration, including components such as a sprinkler valve, water motor gong, pressure alarm switch and retarding chamber. NFPA 25, Section A.3.6.4, states, "[a] sprinkler system is considered to have a single system riser control valve." The staff did not find the applicant's response acceptable because, although the applicant refers to its sprinkler systems as zones, it appears that the zones are individual systems and therefore on an alternating schedule, an internal inspection of every other wet pipe system in buildings with multiple wet pipe systems should be conducted every 5 years.
| |
| Subsequent to a conference call conducted with the applicant on April 8, 2015, by letter dated May 19, 2015, the applicant revised its response to state that it does have multiple wet pipe systems, referred to as zones. The applicant revised Enhancement 5 and Commitment 75 to state that in buildings with multiple wet pipe systems, every other
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| | |
| Aging Management Review Results 3-101 system will have an internal inspection conducted in accordance with NFPA 25, Section 14.2.2, every 5 years.
| |
| The staff finds the applicant's responses acceptable because internal inspections of sprinkler systems will be conducted consistent with LR
| |
| -ISG-2012-02 AMP XI.M27. The inspections are capable of detecting potential flow blockage. The staff's concern addressed in RAI B.2.1.16
| |
| -8 is resolved.
| |
| In addition to addressing Table 4a of LR
| |
| -ISG-2012-02 AMP XI.M27, the applicant also revised its program to address additional details of the revised AMP, including augmented inspections for fire protection system piping that has been wetted but is normally dry. Based on its review, the staff finds that, with the following clarifications and RAIs, the applicant's proposed augmented inspections and acceptance criteria are consistent with LR-ISG-2012-02 AMP XI.M27.
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| * The applicant stated that its plant
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| -specific installation specification for the fixed fire suppression system states that "all piping shall be pitched to permit complete drainage of the system. Drain valves shall be provided at all low points of the system." Based on this, the applicant concluded that no changes were required to address normally
| |
| -dry pipe that is periodically wetted where piping segments allow water to collect. The staff noted that, despite appropriate construction specifications, field installation can result in deviations. In addition, during the first few operational cycles of systems (e.g., system flow), minor changes in pipe elevations can occur. It is not clear to the staff whether the applicant confirmed that there were no piping segments that could allow water to collect in the fire water normally
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| -dry but periodically
| |
| -wetted piping. By letter dated November 18, 2014, the staff issued RAI B.2.1.16
| |
| -9, requesting that the applicant state how it confirmed that there were no piping segments that could allow water to collect in the fire water normally
| |
| -dry but periodically
| |
| -wetted piping.
| |
| In its reply dated March 9, 2015, the applicant stated that the only normally
| |
| -dry but periodically wetted system that is tested with water is the deluge system for the transformers. The deluge system for the transformers has drain holes in each of the branch connections. The applicant revised its program to include a new enhancement, Enhancement 13, and Commitment 88 to "include verification that the drain holes associated with the transformer deluge system are draining to ensure complete drainage of the system after each test."
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| The staff did not find the applicant's response acceptable because: (a) the response did not state that the drain holes and associated piping are configured to completely drain the deluge system piping, and (b) the response did not address normally
| |
| -dry piping that could have been wetted by inadvertent system actuations or those that occur as a result of a fire.
| |
| Subsequent to a conference call conducted with the applicant on April 8, 2015, by letter dated May 19, 2015, the applicant revised Enhancement 13 and Commitment 88 to also state that "normally
| |
| -dry piping that could have been wetted by inadvertent system actuations or those that occur after a fire are restored to a dry state as part of the suppression system restoration."
| |
| | |
| Aging Management Review Results 3-102 The staff finds the applicant's responses acceptable because whenever normally
| |
| -dry piping is wetted, the program has been modified to ensure that the piping has been returned to its dry state. LR
| |
| -ISG-2012-02 AMP XI.M27 recommended enhanced inspections and tests only for those portions of systems that did not drain properly. The staff's concern addressed in RAI B.2.1.16
| |
| -9 is resolved.
| |
| * The staff noted that the applicant did not address the "acceptance criteria" program element of LR
| |
| -ISG-2012-02 AMP XI.M27, which states that, if sufficient foreign organic or inorganic material to obstruct piping or sprinklers is detected, the material should be removed and its source determined and corrected. It is not clear to the staff whether an exception was taken to this portion of the recommendations in the "acceptance criteria" program element of LR
| |
| -ISG-2012-02 AMP XI.M27. By letter dated November 18, 2014, the staff issued RAI B.2.1.16
| |
| -10, requesting that the applicant state what actions will be taken if sufficient foreign organic or inorganic material to obstruct piping or sprinklers is detected.
| |
| In its reply dated March 9, 2015, the applicant stated that, "[i]f the presence of sufficient foreign organic or inorganic material to obstruct pipe or sprinklers is detected during pipe inspections, the material will be removed and its source is determined and corrected in accordance with the acceptance criteria element of LR
| |
| -ISG-2012-02." The applicant revised Enhancement 5 and Commitment 75 to reflect this change.
| |
| The staff finds the applicant's response acceptable because the changes can ensure that debris sufficient to obstruct pipe or sprinklers is removed and corrected, which will reduce the potential for flow blockage of the fire water system. The staff's concern described in RAI B.2.1.16
| |
| -10 is resolved.
| |
| The staff also reviewed the portions of the "parameters monitored or inspected" "detection of aging effects," and "acceptance criteria program elements associated with enhancements to determine if the program will be adequate to manage the aging effects for which it is credited. The staff's evaluation of these enhancements follows.
| |
| Enhancement
| |
| : 1. LRA Section B.2.1.16 states an enhancement to the "detection of aging effects" program element. The applicant stated that it will enhance its program to include the NFPA 25 criteria, which states that "where sprinklers have been in place for 50 years, they will either be replaced or a representative sampling from one or more sample areas will be submitted to a recognized testing laboratory for field service testing." The applicant further stated that sampling will be performed every 10 years after the initial field service testing.
| |
| The staff reviewed this enhancement against the corresponding program element in GALL Report AMP XI.M27. The staff noted that the GALL Report recommends that sprinkler heads be inspected before the end of the 50
| |
| -year sprinkler head service life and at 10
| |
| -year intervals thereafter during the period of extended operation to ensure that signs of degradation, such as corrosion, are detected in a timely manner. The staff finds the applicant's enhancement acceptable because, when implemented, the program element will be consistent with the recommendations in LR
| |
| -ISG-2012-02 AMP XI.M27.
| |
| Enhancement 2. LRA Section B.2.1.16 states an enhancement to the "parameters monitored or inspected" program element. The applicant stated that it will enhance its program to include Aging Management Review Results 3-103 performance of periodic flow testing of the fire water system in accordance with NFPA 25 guidelines.
| |
| The staff reviewed this enhancement against the corresponding program element in GALL Report AMP XI.M27. The staff noted that the GALL Report recommends that periodic flow testing of the fire water system be performed using the guidelines of NFPA 25. The staff finds the applicant's enhancement acceptable because, when implemented, the program element will be consistent with the recommendations in LR
| |
| -ISG-2012-02 AMP XI.M27.
| |
| Enhancement 3. As amended by letter dated March 5, 2014, LRA Section B.2.1.16 states an enhancement to the "detection of aging effects" program element as follows:
| |
| The Seabrook Station Fire Water System Program will be enhanced to include the performance of periodic visual inspection or volumetric inspection, as required, of the internal surface of the fire protection system upon each entry to the system for routine or corrective maintenance to evaluate wall thickness and inner diameter of the fire protection piping ensuring that corrosion product buildup will not result in flow blockage due to fouling. Where surface irregularities are detected, follow
| |
| -up volumetric examinations are performed.
| |
| This inspection will be performed no earlier than 10 years before the period of extended operation.
| |
| In the Safety Evaluation Report with Open Items Related to the License Renewal of Seabrook Station, dated June 8, 2012, the staff documented its evaluation of RAI B.2.1.16
| |
| -1 and RAI B.2.1.16-3, which were related to this enhancement. The discussion and staff evaluation of these RAIs has been removed because the GALL Report AMP XI.M27 recommendations associated with these RAIs were significantly revised in L R-ISG-2012-02 AMP XI.M27. The staff noted that the last sentence of this enhancement had been revised by letter dated November 15, 2010, to state, "[t]hese inspections will be performed within ten years prior to the period of extended operation." It is not clear to the staff: (a) why the applicant reverted to the original wording of the enhancement, (b) why the term "this" inspection was used when the enhancement states that periodic inspections will be conducted, and (c) if the intent is to conduct periodic inspections in the 10
| |
| -year period prior to the period of extended operation and during the period of extended operation, why this sentence does not refer to the inspections "commencing" during the 10
| |
| -year period prior to the period of extended operation. By letter dated November 18, 2014, the staff issued RAI B.1.1.16
| |
| -11, requesting that the applicant clarify its intent and the wording of Enhancement 3 and Commitment 11.
| |
| In its reply dated March 9, 2015, the applicant stated that the term "this inspection" was revised to "these inspections." The applicant also stated that the intent of Enhancement 3 and Commitment 11 is to commence the inspections in the 10
| |
| -year period prior to the period of extended operation. Commitment 11 states the following:
| |
| Enhance the program to include the performance of periodic visual or volumetric inspection of the internal surface of the fire protection system upon each entry to the system for routine or corrective maintenance to evaluate wall thickness and inner diameter of the fire protection piping ensuring that corrosion product buildup will not result in flow blockage due to fouling. Where surface irregularities are detected, follow
| |
| -up volumetric examinations are performed. These inspections will be documented and trended to determine if a Aging Management Review Results 3-104 representative number of inspections have been performed prior to the period of extended operation. If a representative number of inspections have not been performed prior to the period of extended operation, focused inspections will be conducted. These inspections will be performed within ten years prior to the period of extended operation.
| |
| The staff does not find the applicant's response acceptable. Although the applicant stated its intent to commence the volumetric inspections in the 10
| |
| -year period prior to the period of extended operation, its intent is not consistent with the wording in Enhancement 3 and Commitment 11. The wording of the enhancement and commitment refer to the volumetric inspections as, "these inspections." The last sentence of the enhancement and commitment state that, "[t]hese inspections will be performed within ten years prior to the period of extended operation." This last sentence is not consistent with an intent that the inspections would commence during the 10
| |
| -year period prior to the period of extended operation and continue through the period of extended operation.
| |
| Subsequent to a conference call conducted with the applicant on April 8, 2015, by letter dated May 19, 2015, the applicant revised Enhancement 3 and Commitment 11 to state that the inspections will commence during the 10
| |
| -year period prior to the period of extended operation and continue throughout the period of extended operation.
| |
| The staff finds the applicant's response acceptable because, consistent with LR
| |
| -ISG-2012-02 AMP XI.M27: (a) periodic internal visual inspections are capable of detecting surface irregularities that could be indicative of wall loss, (b) when surface irregularities are detected, followup volumetric examinations will be conducted to determine the actual wall thickness in the vicinity of the surface irregularity, (c) the inspections will commence prior to the period of extended operation and be conducted throughout the period of extended operation, and (d) inspections conducted in this manner are capable of detecting loss of material prior to a loss of intended function of the fire water system piping. The staff's concern addressed in RAI B.1.1.16-11 is resolved. Enhancement 4. LRA Section B.2.1.16, as amended by letter dated March 5, 2014, states an enhancement to the "detection of aging effects" program element. The applicant stated that it will enhance its program to include internal UT inspections of the FWST bottom surfaces and the inspections will be conducted in accordance with the guidance in NFPA 25 (2011 Edition). In addition, in Enhancement 8 and Commitment 13, the applicant stated that FWST external inspections would be conducted on an annual basis. The staff finds the applicant's enhancements associated with internal and external inspections of the FWST acceptable because, when implemented, the program element will be consistent with the recommendations in LR-ISG-2012-02 AMP XI.M27. The staff's evaluation of the inspections conducted on the FWST is documented in the discussion of RAI B.1.1.16
| |
| -5, above.
| |
| Enhancement 5. LRA Section B.2.1.16, as amended by letters dated March 5, 2014; March 9, 2015; and May 19, 2015, states an enhancement to the "detection of aging effects" program element. The applicant stated that it will enhance its program to "conduct an inspection of piping and branch line conditions every 5 years by opening a flushing connection at the end of one main and by removing a sprinkler toward the end of one branch line for the purpose of inspecting for the presence of foreign organic and inorganic material per the guidance provided in NFPA 25 (2011 Edition)." The applicant also stated that in buildings with multiple wet pipe systems, every other system will have an internal inspection conducted in accordance with Aging Management Review Results 3-105 NFPA 25, Section 14.2.2, every 5 years. The applicant further stated that, "[i]f the presence of sufficient foreign organic or inorganic material to obstruct pipe or sprinklers is detected during pipe inspections, the material will be removed and its source is determined and corrected in accordance with the acceptance criteria element of LR
| |
| -ISG-2012-02." The staff's evaluation of this enhancement is documented in the discussion associated with RAI B.1.1.16
| |
| -8 and RAI B.1.1.16-10, above.
| |
| Enhancement 6. LRA Section B.2.1.16, as amended by letter dated March 5, 2014, states an enhancement to the "detection of aging effects" program element. The applicant stated that it will enhance its program to perform annual sprinkler inspections in accordance with NFPA 25 (2011 Edition). The inspections will be conducted to detect corrosion, foreign materials, paint, and physical damage and to ensure that the sprinklers are installed in the proper orientation. Sprinklers with evidence of degradation will be evaluated for replacement. The staff finds the applicant's enhancement acceptable because, when implemented, the program element will be consistent with the recommendations in LR
| |
| -IS G-2012-02 AMP XI.M27.
| |
| Enhancement 7. LRA Section B.2.1.16, as amended by letter dated March 5, 2014, states an enhancement to the "detection of aging effects" program element. The applicant stated that it will enhance its program to require that main drain tests, deluge valve trip tests, and FWST exterior surface inspections are conducted on an annual basis. The staff finds the applicant's enhancement acceptable because, when implemented, the program element will be consistent with the recommendations i n LR-ISG-2012-02 AMP XI.M27.
| |
| Enhancement 8. LRA Section B.2.1.16, as amended by letter dated March 5, 2014, states an enhancement to the "detection of aging effects" and "acceptance criteria" program elements. The applicant stated that it will enhance its program in regard to main drain testing to include recording the time taken for the fire water system supply pressure to return to the static flow pressure and, if there is a 10 percent reduction in full flow pressure when compared to the original acceptance value or previously performed test, the cause will be determined and corrected, if necessary. The staff finds the applicant's enhancement acceptable because, when implemented, the program elements will be consistent with the recommendations in LR
| |
| -I SG-2012-02 AMP XI.M27.
| |
| Enhancement 9. LRA Section B.2.1.16, as amended by letter dated March 5, 2014, states that the Fire Water System Program will be augmented to include the requirements associated with managing loss of coating integrity. The staff's evaluation of the changes associated with coating integrity is documented in SER Section 3.0.3.4.
| |
| Enhancement 10. LRA Section B.2.1.16, as amended by letter dated March 9, 2015, states that the Fire Water System Program will be enhanced to perform additional tests and inspections on the interior of the fire water storage tanks as required by NFPA 25, Section 9.2.7, when NFPA 25, Section 9.2.6.4, requires the additional tests and inspections to be implemented. The staff's evaluation of this enhancement is documented above in the response to RAI B.2.1.16
| |
| -5. Enhancement 11. LRA Section B.2.1.16, as amended by letter dated March 9, 2015, states that the Fire Water System Program will be enhanced to perform disassembly, inspection, and cleaning of the mainline strainers every 5 years, in accordance with NFPA 25, Section 10.2.1.7. The staff's evaluation of this enhancement is documented above in the response to RAI B.2.1.16-6.
| |
| Aging Management Review Results 3-106 Enhancement 12. LRA Section B.2.1.16, as amended by letter dated March 9, 2015, states that the Fire Water System Program will be enhanced to conduct open head spray nozzle air flow tests every refueling outage interval in lieu of every 3 years. The staff's evaluation of this enhancement is documented above in the response to RAI B.2.1.16-7. Enhancement 13. LRA Section B.2.1.16, as amended by letters dated March 9, 2015, and May 19, 2015, states that the Fire Water System Program will be enhanced to include verification that: (a) "the drain holes associated with the transformer deluge system are draining to ensure complete drainage of the system after each test"; (b) "the deluge system drains and associated piping are configured to completely drain the piping"; and (c) "normally
| |
| -dry piping that could have been wetted by inadvertent system actuations or those that occur after a fire are restored to a dry state as part of the suppression system restoration." The staff's evaluation of this enhancement is documented above in the response to RAI B.2.1.16
| |
| -9. Based on its audit, review of the application, and review of the applicant's responses to RAIs B.2.1.16-4 through B.2.1.16
| |
| -11, the staff finds that elements one through six of the applicant's Fire Water System Program, with acceptable enhancements, are consistent with the corresponding program elements of LR
| |
| -ISG-2012-02 AMP XI.M27 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.16 summarizes operating experience related to the Fire Water System Program. The applicant stated that, in July 2003, a surveillance activity identified a failure to develop required discharge pressure for the fire protection booster pump. The applicant also stated it determined the pump was not sized correctly and replaced the impeller. The applicant further stated that, in July 2004, a maintenance mechanic observed pipe corrosion in the fire pump recirculation header and that a work order was written and the pipe was replaced. The applicant stated that these examples provide evidence of how its routine system maintenance is able to identify deficient conditions and correct them with its corrective action program.
| |
| The staff reviewed operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program. During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.16, as amended by letters dated December 17, 2010 and March 5, 2014, provides the UFSAR supplement for the Fire Water System Program. Prior to the issuance of LR
| |
| -ISG-2012-02, the staff reviewed this UFSAR supplement description of the program against the recommended description for this type of program, as described in Aging Management Review Results 3-107 SRP-LR Table 3.3
| |
| -2. The staff noted that it did not indicate that periodic full
| |
| -flow flush tests and system performance testing are performed or that the visual inspections included in the program will be able to detect wall thickness and the inner diameter of the piping. The licensing basis for the period of extended operation may not be adequate if the applicant does not incorporate this information in its UFSAR supplement. By letter dated November 18, 2010, the staff issued RAI B.2.1.16-2 to request that the applicant justify why it did not indicate that periodic full
| |
| -flow flush tests and system performance testing are performed and that the visual inspections in the program will be able to detect wall thickness and the inner diameter of the piping.
| |
| In its response dated December 17, 2010, the applicant stated that it revised LRA Section A.2.1.16 to state that the Fire Water System Program includes periodic full
| |
| -flow flush tests and system performance testing per the guidance of NFPA 25. The applicant also revised the UFSAR supplement to state that the program also includes visual inspection of the internal surface of the fire protection piping upon each entry into the system for routine or corrective maintenance that will look for material loss or changes to the inner diameter of the piping. The staff finds the applicant's response acceptable because the applicant revised its UFSAR supplement to include periodic flushing and internal visual inspections, which is consistent with the recommended description for this type of program, as described in SRP
| |
| -LR Table 3.3
| |
| -2. The staff's concern described in RAI B.2.1.16
| |
| -2 is resolved.
| |
| By letter dated March 5, 2014, the applicant revised LRA Section A.2.1.16 to address loss of coating integrity. The staff's evaluation of the UFSAR supplement changes associated with coatings is documented in SER Section 3.0.3.4.
| |
| The staff noted that, as amended by letter dated March 5, 2014, the applicant committed (Commitment Nos. 9, 10, 11, 13, 74, 75, 76, 77, 80, and 85 through 88) to enhancing the Fire Water System Program prior to entering the period of extended operation, as described in the above discussion of each enhancement.
| |
| The staff determined that the information in the UFSAR supplement, as amended, is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its audit and review of the applicant's Fire Water System Program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the enhancements and confirmed that their implementation through Commitment Nos. 9, 10, 11, 13, 74, 75, 76, 77, 80, and 85 through 88 prior to, and in some instances, within 10 years prior to the period of extended operation would make the existing AMP consistent with the GALL Report to which it was compared. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.2.9 Aboveground Steel Tanks Program Summary of Technical Information in the Application. LRA Section B.2.1.17, as amended by letters dated December 17, 2010; March 5, 2014; and March 9, 2015, describes the existing Aboveground Steel Tanks Program as consistent, with enhancements, with GALL Report AMP XI.M29, "Aboveground Metallic Tanks," as modified by LR
| |
| -IGS-2012-02, "Aging
| |
| | |
| Aging Management Review Results 3-108 Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation." The applicant stated that the Aboveground Steel Tanks Program manages the aging effects of cracking and loss of material due to general, pitting, and crevice corrosion on all outdoor and certain large volume indoor tanks. The applicant also stated that the program includes preventive measures to mitigate corrosion and periodic inspections to validate the effectiveness of the preventive actions. The applicant further stated that the preventive measures include the application of protective coatings on the exterior surfaces of steel tanks and caulking and flashing at the ground interface of the auxiliary boiler fuel oil storage tank. The AMP inspects inside and outside surfaces of tanks using visual, surface, or volumetric examinations. Ultrasonic thickness measurements are performed on inaccessible areas, such as tank bottoms, from inside the tank to detect any exterior material degradation.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.M29. As discussed in the audit report, the staff confirmed that each element of the applicant's program is consistent with the corresponding element of GALL Report AMP XI.M29, with the exception of the "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements. For these elements, the staff determined the need for additional clarification, which resulted in the issuance of RAIs.
| |
| GALL Report AMP XI.M29 recommends that the program use periodic system walkdowns to monitor degradation of the protective paint or coating under the "parameters monitored or inspected" program element description. However, LRA Section B.2.1.17 states that visual inspection of the external surface of the protective coatings on exterior surface of the in
| |
| -scope tanks will be conducted in accordance with the Structures Monitoring Program. The staff noted that this program does not state that coating inspections of aboveground steel tanks are within its scope. By letter dated November 18, 2010, the staff issued RAI B.2.1.17
| |
| -1, requesting that the applicant confirm that its Structures Monitoring Program includes coating inspection of aboveground steel tanks.
| |
| In its response dated December 17, 2010, the applicant stated that its Structures Monitoring Program is revised to include an external inspection of the aboveground steel tanks to inspect the paint or coating for cracking, flaking, or peeling. The staff finds the applicant's response acceptable because the applicant's Structures Monitoring Program includes coating inspection of the aboveground steel tanks to monitor degradation of the coatings. The staff's concern described in RAI B.2.1.17
| |
| -1 is resolved.
| |
| GALL Report AMP XI.M29 recommends that periodic system walkdowns be conducted to confirm that the sealant and caulking at the interface edge between the tank and concrete are intact under the "parameters monitored or inspected" and "detection of aging effects" program element descriptions. The staff noted that LRA Section B.2.1.17 states that visual inspection will be performed to detect drying, cracking, or missing sealant and caulking applied along the tank and ground interface. The staff has concluded that, in order to detect hardening and loss of strength in elastomeric materials, it is necessary to supplement visual inspections with physical manipulation of the sealant and caulking. By letter dated November 18, 2010, the staff issued RAI B.2.1.17
| |
| -3, requesting that the applicant confirm that its Aboveground Steel Tanks Aging Management Review Results 3-109 Program includes manual manipulation of elastomeric sealant and caulking material to detect hardening and loss of strength.
| |
| In its response dated December 17, 2010, the applicant stated that its Aboveground Steel Tanks Program is revised to include a visual and tactile examination of the sealant and caulking on the exterior surfaces of the aboveground steel tanks. The applicant also stated that the examination consists of pressing on the sealant or caulking to detect a reduction in the resiliency and pliability. The staff finds the applicant's response acceptable because the applicant's Aboveground Steel Tanks Program includes visual inspections and physical manipulation, which are capable of detecting degradation of the sealant and caulking. The staff's concern described in RAI B.2.1.17
| |
| -3 is resolved.
| |
| GALL Report AMP XI.M29 recommends that "[a]ny degradation of paint, coating, sealant, and caulking is reported and will require further evaluation. Degradation consists of cracking, flaking, or peeling of paint or coatings, and drying, cracking or missing sealant and caulking" under the "acceptance criteria" program element description. The staff noted that LRA Section B.2.1.17 states an enhancement to the Aboveground Steel Tanks Program by adding paint flaking and drying, cracking, or missing sealant and caulking as examples of minor structural deficiencies. The staff does not understand the context of the term "minor structural deficiencies" and how it relates to the need for further evaluation of the condition. By letter dated November 18, 2010, the staff issued RAI B.2.1.17
| |
| -4, requesting that the applicant clarify whether the term "minor structural deficiency" implies that no further evaluation of the degraded condition will occur, and, if no further evaluation will occur, the staff asked the applicant to justify this as an exception to GALL Report AMP XI.M29.
| |
| In its response dated December 17, 2010, the applicant stated that the term "minor structural deficiency" in LRA Section B.2.1.17 is revised to "degradation." The staff finds the applicant's response acceptable because the applicant has changed the term "minor structural deficiency" to "degradation" in its Aboveground Steel Tanks Program; therefore, all degraded conditions will be entered into its corrective action program. The staff's concern described in RAI B.2.1.17
| |
| -4 is resolved.
| |
| GALL Report AMP XI.M29 recommends that, "[t]he effects of corrosion of the underground external surface are detectable by thickness measurement of the tank bottom and are monitored and trended if significant material loss is detected" under the "monitoring and trending" program element description. The staff noted that LRA Section B.2.1.17 states that, for the two fire protection water storage tanks, the program will be enhanced to include the performance of an ultrasonic (UT) examination of the internal tank bottom surface within 10 years prior to the period of extended operation. The staff is not clear whether the UT examination is a one
| |
| -time or periodic inspection. By letter dated November 18, 2010, the staff issued RAI B.2.1.17
| |
| -5, requesting that the applicant clarify whether the UT examination specified in LRA Section B.2.1.17 is a one
| |
| -time measurement or periodic inspection. If it is a one-time ultrasonic inspection, the staff asked the applicant to justify how the one
| |
| -time measurement can be used for monitoring and trending of aging effects.
| |
| In its response dated December 17, 2010, the applicant stated that a one
| |
| -time ultrasonic thickness measurement of the tank bottoms will be performed within 10 years prior to the period of extended operation (Commitment 13). The applicant also stated that any thickness measurements indicating less than nominal thickness will require a condition report to ensure than an engineered evaluation is performed and any necessary monitoring and trending is Aging Management Review Results 3-110 identified. The staff finds the applicant's response acceptable because the applicant will perform an engineering evaluation of any thickness measurements less than nominal thickness and the evaluation will identify any required monitoring and trending. The staff's concern described in RAI B.2.1.17
| |
| -5 is resolved.
| |
| Subsequent to the submittal of the LRA, the staff issued LR
| |
| -ISG-2012-02, which revised several GALL Report AMPs, including the guidance for AMP XI.M29. The revision to AMP XI.M29 includes cracking as an aging effect and provides updated guidance for the AMP elements. Element 4, "detection of aging effects," has been updated to include Table 4a, "Tank Inspection Recommendations," and accompanying table notes. The guidance provided in LR
| |
| -ISG-2012-02 for managing the aging effects of the fire water storage tanks is to use GALL Report AMP XI.M27. By letter dated March 5, 2014, the applicant submitted an LRA supplement in response to LR
| |
| -ISG-2012-02. The LRA supplement revised the applicant's Aboveground Steel Tanks Program, including Enhancements 1 and 2, as described below.
| |
| The staff also reviewed the portions of the "scope of program," "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements associated with enhancements to determine if the program will be adequate to manage the aging effects for which it is credited. The staff's evaluation of these enhancements follows.
| |
| Enhancement 1. LRA Section B.2.1.17 states an enhancement to the "scope of program,"
| |
| "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements. The LRA, as updated by the applicant's response to RAI B.2.1.17
| |
| -4, dated December 17, 2010, and letter dated March 5, 2014, states that the Aboveground Steel Tanks Program implementing procedures will be enhanced to do the following:
| |
| * Include the fire protection fuel oil tanks, auxiliary boiler fuel oil storage tank, refueling water storage tank, reactor makeup water storage tank, and condensate storage tank as part of the scope of tanks.
| |
| * Add paint flaking and drying, cracking, or missing sealant and caulking as examples of degradation.
| |
| * Add a requirement that discrepant conditions be reported through the applicant's corrective action program.
| |
| The staff reviewed this enhancement against the corresponding program elements in GALL Report AMP XI.M29, as modified by LR
| |
| -ISG-2012-02. The staff noted that the applicant's program appropriately identifies specific components, aging effects, and the need for corrective actions to ensure that aging effects are managed. The staff's evaluation of RAI B.2.1.17
| |
| -4 related to the applicant changing the term "minor structural deficiency" to "degradation" in its Aboveground Steel Tanks Program is documented above. On the basis of its review, the staff finds this enhancement acceptable because, when it is implemented prior to the period of extended operation, it will make the program elements consistent with the recommendations in GALL Report AMP XI.M29 as modified by LR
| |
| -ISG-2012-02.
| |
| Aging Management Review Results 3-111 Enhancement 2. LRA Section B.2.1.17, as amended by letter dated March 5, 2014, states an enhancement to the "scope of program," "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements. The LRA states that the Aboveground Steel Tanks Program implementing procedures will be enhanced to include the performance of visual, surface, and volumetric examinations of the tanks identified in Enhancement 1 as described below:
| |
| * For managing loss of material on the internal surfaces of stainless steel tanks exposed to treated water, the applicant states that visual inspections or volumetric examinations, consistent with the guidance provided in Table 4a of LR
| |
| -ISG-2012-02 and applicable table notes, will be performed.
| |
| * For managing cracking on the external surfaces of stainless steel tanks exposed to uncontrolled indoor air, the applicant states that surface examinations, consistent with the guidance provided in Table 4a of LR
| |
| -ISG-2012-02 and applicable table notes, will be performed every 10 years.
| |
| * For managing loss of material and cracking on external surfaces of stainless steel tanks exposed to outdoor air, the applicant states that it will perform visual examinations and surface examinations, respectively. The frequency of the proposed visual and surface examinations is consistent with the guidance provided in Table 4a of LR
| |
| -IS G-2012-02 and applicable table notes.
| |
| * For managing loss of material on external surfaces of stainless steel tanks exposed to soil or concrete, the applicant states that volumetric examinations, consistent with the guidance provided in Table 4a of LR
| |
| -ISG-2 012-02 and applicable table notes, will be performed every 10 years.
| |
| * For managing loss of material on the external surfaces of steel tanks exposed to outdoor air, the applicant states that visual examinations, consistent with the guidance provided in Table 4a of LR
| |
| -ISG-2012-02 and applicable table notes, will be performed every 18 months.
| |
| * For managing loss of material on the external surfaces of steel tanks exposed to soil or concrete, the applicant states that volumetric examinations, consistent with the guidance provided in Table 4a of LR
| |
| -ISG-2012-02 and applicable table notes, will be performed from the inside of the tank every 10 years.
| |
| The staff reviewed this enhancement against the corresponding program elements in GALL Report AMP XI.M29, as modified by LR-ISG-2012-02. On the basis of its review, the staff finds this enhancement acceptable because, when it is implemented prior to the period of extended operation, it will make the program elements consistent with the recommendations in GALL Report AMP XI.M29 as modified by LR
| |
| -ISG-2012-02. Based on its audit, review of the application, and review of the applicant's response to RAIs B.2.1.17-1, B.2.1.17
| |
| -3, B.2.1.17
| |
| -4, and B.2.1.17
| |
| -5, the staff finds that elements one through six of the applicant's Aboveground Steel Tanks Program, with acceptable enhancements, are consistent with the corresponding program elements of GALL Report AMP XI.M29, as modified by LR
| |
| -ISG-2012-02 and, therefore, are acceptable.
| |
| | |
| Aging Management Review Results 3-112 Operating Experience. LRA Section B.2.1.17 summarizes operating experience related to the Aboveground Steel Tanks Program. The applicant stated that degradation of coatings was reported on the fire protection fuel oil tanks in 1999. As a result, the applicant stated that the tanks were surface prepped and re-coated. The applicant also stated that, in response to a condition of chipped paint and rusting metal surface around the lower manways of the fire protection water storage tanks in 2001, it took appropriate corrective actions to have the tanks surface prepped and re
| |
| -coated to maintain the structural integrity of the tanks.
| |
| The staff reviewed operating experience information in the application and during the audit to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program.
| |
| During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.17, as amended by letters dated December 17, 2010; March 5, 2014; and March 9, 2015, provides the UFSAR supplement for the Aboveground Steel Tanks Program. The staff reviewed this UFSAR supplement description of the program against the recommended description for this type of program, as described in LR
| |
| -I SG-2012-02 AMP XI.M29 Table 3.0
| |
| -1. The staff reviewed the applicant's UFSAR supplement and found that it does not indicate that visual inspections of sealant and caulking inspections are included in the program. The example description for this program in SRP-LR Table 3.0
| |
| -1 includes specific mention of this inspection. The licensing basis for the period of extended operation may not be adequate if the applicant does not incorporate this information in its UFSAR supplement. By letter dated November 18, 2010, the staff issued RAI B.2.1.17
| |
| -2, requesting that the applicant justify why visual inspections of sealant and caulking are not included in the UFSAR supplement as part of the scope of the program.
| |
| In its response dated December 17, 2010, the applicant stated that it revised its UFSAR supplement, Section A.2.1.17, to include visual inspections of the sealant and caulking on the exterior surfaces of the aboveground steel tanks. The staff finds the applicant's response acceptable because the applicant revised its Aboveground Steel Tanks Program UFSAR supplement to include visual inspections of the sealant and caulking in the program; therefore, the licensing basis is now adequate. The staff's concern described in RAI B.2.1.17
| |
| -2 was resolved; however, subsequent to the response to RAI B.2.1.17
| |
| -2, SRP-LR Table 3.0
| |
| -1 was modified by LR
| |
| -ISG-2012-02 to state that external visual examinations are sufficient to monitor the degradation of caulking and sealant when supplemented with physical manipulation. The staff noted that the UFSAR supplement (LRA Section A.2.1.17) does not state that visual Aging Management Review Results 3-113 examinations of caulking and sealant are supplemented with physical manipulation. By letter dated November 18, 2014, the staff issued RAI B.2.1.17
| |
| -6, requesting justification for not supplementing the visual examinations of caulking and sealant with physical manipulation.
| |
| In its response dated March 9, 2015, the applicant revised LRA section A.2.1.17 to state that both visual and tactile examinations will be performed on sealant and caulking to detect degradation. The staff finds the applicant's response acceptable because the examinations performed on the sealant and caulking are consistent with LR
| |
| -ISG-2012-02 Table 3.0
| |
| -1. The staff's concern described in RAI B.2.1.17
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| -6 is resolved.
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| The staff noted that the applicant committed (Commitment 12) to enhancing the Aboveground Steel Tanks Program prior to the period of extended operation. However, the commitment did not reflect the details of the enhancements to the program.
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| By letter dated November 18, 2010, the staff issued RAI B.2.1.17
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| -7, requesting that the applicant clarify how the enhancements to the program are captured in the associated commitment.
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| In its response dated March 9, 2015, the applicant revised Commitment 12 to include a summary description of Enhancements No. 1 and 2 evaluated above. The staff's concern described in RAI B.2.1.17
| |
| -7 is resolved.
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| As a result of the two fire protection water storage tanks being within the scope of the Fire Water System Program, Commitment 13, associated with conducting UT examinations of the fire protection water storage tanks, is now assigned to the Fire Water System Program. The staff's evaluation of the changes to the Fire Water System Program is documented in SER Section 3.0.3.2.8.
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| The staff determined that the information in the UFSAR supplement, as amended, is an adequate summary description of the program, as required by 10 CFR 54.21(d).
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| Conclusion. On the basis of its audit and review of the applicant's Aboveground Steel Tanks Program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that their implementation through Commitment 12 prior to the period of extended operation would make the AMP consistent with the GALL Report AMP to which it is compared. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
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| 3.0.3.2.10 Fuel Oil Chemistry Program Summary of Technical Information in the Application. LRA Section B.2.1.18 describes the existing Fuel Oil Chemistry Program as consistent, with exceptions and enhancements, with GALL Report AMP XI.M30, "Fuel Oil Chemistry." The applicant stated that the existing Fuel Oil Chemistry Program manages the aging effects of loss of material due to general, pitting, crevice, galvanic, and microbiologically
| |
| -influenced corrosion as well as loss of material due to fouling in the diesel fuel oil systems for the emergency diesel generators, diesel engine driven fire protection system pumps, and the auxiliary boiler fuel oil system. The program manages the aging effects through monitoring and maintenance of diesel fuel oil quality. The applicant Aging Management Review Results 3-114 further states that the program manages these aging effects for the diesel generator fuel oil storage tanks, the diesel generator fuel oil day tanks, the diesel fire pump fuel oil day tanks, the auxiliary boiler fuel oil storage tank and the associated piping, tubing, and valves. The program manages such aging by maintaining fuel oil chemistry, removing water, and cleaning and inspecting the tanks. As amended by letter dated March 5, 2014, the applicant stated that the program also manages loss of coating integrity for tank internal coatings.
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| During the course of the staff's review, the applicant submitted amendments to the application, and these are discussed in the staff's evaluation below, as appropriate.
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| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
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| The staff also reviewed the portions of the "scope of program," "preventive actions," "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements associated with exceptions and enhancements to determine if the program will be adequate to manage the aging effects for which it is credited. The staff's evaluation of these exceptions and enhancements follows.
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| The staff also reviewed the portions of the "scope of program," "preventive actions," "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements associated with exceptions and enhancements to determine if the program will be adequate to manage the aging effects for which it is credited. The staff's evaluation of these exception and enhancements follows.
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| Exception 1. LRA Section B.2.1.18 states an exception to the "preventive actions" program element. The GALL Report recommends maintaining the quality of fuel oil by additions of biocides to minimize biological activity, stabilizers to prevent biological breakdown of the diesel fuel, and corrosion inhibitors to mitigate corrosion. Alternatively, the applicant stated that plant operating experience has shown that monthly testing for and removal of water along with the purchase of quality fuel oil negates the need for stabilizers or corrosion inhibitors. All new fuel shipments are sampled from the delivery tanker to verify they meet the applicable American Society for Testing and Materials (ASTM) standards prior to being offloaded into the associated storage tank. The applicant stated further that the fuel oil is used and topped off often enough to negate the need for stabilizers or corrosion inhibitors.
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| The staff reviewed this exception with the GALL Report and noted that the applicant took exception because stabilizers or corrosion inhibitors are not used in the diesel fuel oil. Additionally, biocide is added only to the diesel fuel oil storage tanks. The staff finds this exception acceptable and this program element consistent to the one described in the GALL Report because the applicant manages the aging effects of the components by maintaining fuel oil chemistry through monthly sampling, removal of any accumulated water if found, and cleaning and inspecting the associated fuel oil tanks. The applicant also ensures the quality of the fuel oil purchased by sampling each fuel oil shipment prior to being offloaded. These actions demonstrate the intent to minimize biological activity, prevent biological breakdown of the diesel fuel, and mitigate corrosion, as recommended in the GALL Report AMP XI.M30.
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| Exception 2. LRA Section B.2.1.18 states an exception to the "parameters monitored or inspected" and "acceptance criteria" program elements. The GALL Report recommends using Aging Management Review Results 3-115 the modified ASTM Standard D2276, Method A, for determination of particulates. The modification consists of using a filter with a pore size of 3.0 µm instead of 0.8 µm to filter the particulates from the fuel oil sample for subsequent analysis. Alternatively, the applicant stated that the non
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| -modified ASTM Standard D2276, which uses the 0.8 µm filter, is used to sample particulates. The applicant further states that the small pore size of the 0.8 µm filter retains more particulates and, therefore, is conservative as the analysis for particulates is based on the total weight of particulates captured.
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| The staff reviewed this exception with the GALL Report and noted that the applicant took exception because the non
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| -modified ASTM Standard D2276 is used for the analysis of particulates in fuel oil. The staff finds this exception acceptable because the analysis for particulates is based on the total weight of particulates captured; therefore, using a smaller pore sized filter will make the applicant's analysis of particulates more conservative than what is recommended in the GALL Report AMP XI.M30.
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| Exception 3. LRA Section B.2.1.18 states an exception to the "parameters monitored or inspected" and "acceptance criteria" program elements. The GALL Report recommends using the ASTM Standards D1796 and D2709 for determination of water and sediment contamination in diesel fuel. Alternatively, the applicant stated that ASTM Standards D4176 and D2709 would be used for determination of water and sediment contamination in diesel fuel. The applicant further stated that ASTM Standard D4176 is used to perform a clear and bright test of light fuel oil and can be performed in the field as well as in the lab and is an easy first screening to determine the quality of fuel oil. The applicant stated that using one lab test to analyze for water and particulate coupled with the field clear and bright test provides an acceptable approach for detecting water and particulates in the delivered diesel generator fuel oil.
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| The staff noted that the applicant took exception to the GALL Report in that the applicant incorporates ASTM Standard D4176 versus D1796 for the use in detecting water and particulates in fuel oil. The staff finds this exception acceptable because the detection limit of ASTM Standard D4176 for free water and particulate contamination, with an experienced operator, is approximately 40 ppm and is not dependent on ambient temperature above the cloud point of the fuel. The detection limit for ASTM Standard D2709 is 50 ppm at 21-32 °Celsius (C). The staff finds the use of ASTM Standard D4176 an acceptable substitute to ASTM Standard D1796 because it allows the applicant to have an immediate indication of any contamination in a fuel delivery prior to allowing the fuel to reach the fuel storage tanks.
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| The use of ASTM Standard D4176 along with ASTM Standard D2709 allows two separate checks of the fuel oil using two different analyses with similar detection limits. The staff finds the use of these two standards consistent with the GALL Report AMP XI.M30.
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| Exception 4. LRA Section B.2.1.18 states an exception to the "parameters monitored or inspected" and "acceptance criteria" program elements. The GALL Report recommends using ASTM Standard D2276
| |
| -00 for determining particulate in diesel fuel oil. Alternatively, the applicant uses ASTM Standard D2276
| |
| -06. The applicant stated that the basic methodology between the two revisions of the standards had not changed, and the 2006 version of the standard had updated figures and notes from previous revisions that were incorporated into the procedural steps. The applicant further stated that the figure and methodology for taking aviation jet fuel samples had changed but is not used by the applicant.
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| | |
| Aging Management Review Results 3-116 The staff noted that the applicant took exception to the GALL Report in that the applicant uses ASTM Standard D2276
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| -06 versus ASTM Standard D2276
| |
| -00. The staff reviewed both revisions of the standard and finds that this exception is acceptable because the methodology for determining particulate in diesel fuel oil has not changed between the two revisions. The applicant's use of ASTM Standard D2276
| |
| -06 is consistent with the GALL Report AMP XI.M30.
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| Enhancement 1. LRA Section B.2.1.18 states an enhancement to the "scope of program," "preventive actions," "parameters monitored or inspected," and "monitoring and trending" program elements. This enhancement expands on the existing program elements by adding the requirement to sample and analyze new fuel deliveries, including testing for biodiesel, prior to offloading to the auxiliary boiler fuel oil storage tank. Additionally, the enhancement will require that the auxiliary boiler fuel oil storage tank be sampled periodically.
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| On the basis of its review, the staff finds this enhancement acceptable because, when it is implemented, prior to the period of extended operation, it will make the program consistent with the recommendations of GALL Report AMP XI.M30.
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| Enhancement 2. LRA Section B.2.1.18 states an enhancement to the "preventive actions" program element. This enhancement expands on the existing program element by adding the requirement to check for the presence of water in the auxiliary boiler fuel oil storage tank at least once per quarter and to remove water as necessary.
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| On the basis of its review, the staff finds this enhancement acceptable because, when it is implemented, prior to the period of extended operation, it will make the program consistent with the recommendations of GALL Report AMP XI.M30.
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| Enhancement 3. LRA Section B.2.1.18 states an enhancement to the "scope of program," "preventive actions," "parameters monitored or inspected," and "monitoring and trending" program elements. This enhancement expands on the existing program elements by adding the requirement to drain, clean, and inspect the diesel fire pump fuel oil day tanks on a frequency of at least once every 10 years.
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| On the basis of its review, the staff finds this enhancement acceptable because, when it is implemented, prior to the period of extended operation, it will make the program consistent with the recommendations of GALL Report AMP XI.M30.
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| Enhancement 4. LRA Section B.2.1.18 states an enhancement to the "preventive actions" and "detection of aging effects" program elements. This enhancement expands on the existing program elements by adding the requirement to perform an ultrasonic thickness measurement of the tank bottom during the 10
| |
| -year draining, cleaning, and inspection of the diesel generator fuel oil storage tanks, diesel generator fuel oil day tanks, diesel fire pump fuel oil day tanks, and auxiliary boiler fuel oil storage tank.
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| On the basis of its review, the staff finds this enhancement acceptable because, when it is implemented, prior to the period of extended operation, it will make the program consistent with the recommendations of GALL Report AMP XI.M30.
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| Enhancement 5. LRA Section B.2.1.18 states an enhancement to the "parameters monitored or inspected" and "acceptance criteria" program elements. By letter dated December 14, 2010, the staff issued RAI B.2.1.18
| |
| -2, requesting that the applicant clarify the revisions of ASTM Aging Management Review Results 3-117 standards used for the program. In its response dated January 13, 2011, the applicant amended this enhancement by updating the Technical Requirement Program 5.1 (Diesel Fuel Oil Testing Program) to use ASTM Standards D2709
| |
| -96 and D4057
| |
| -95, as required by GALL Report AMP XI.M30, Revision 1, prior to the period of extended operation. The current revision of the applicant's Technical Requirement Program 5.1 uses ASTM Standards D2709
| |
| -82 and D4057-81. On the basis of its review, the staff finds this enhancement acceptable because, when it is implemented, prior to the period of extended operation, it will make the program consistent with the recommendations of GALL Report AMP XI.M30.
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| Enhancement 6. LRA Section B.2.1.18 (existing Fuel Oil Chemistry Program), as amended by letter dated March 5, 2014, states that the program will be enhanced to include th e requirements associated with managing loss of coating integrity. The staff's evaluation of the changes (Aging Management Related to Loss of Coating Integrity for Internal Coatings on In
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| -Scope Mechanical SSCs Program) is documented in SER Section 3.0.3.4.1. Based on its audit, review of the application, and review of the applicant's response to RAI B.2.1.18
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| -2, the staff finds that elements one through six of the applicant's Fuel Oil Chemistry Program, with acceptable exceptions and enhancements, are consistent with the corresponding program elements of GALL Report AMP XI.M30 and, therefore, are acceptable.
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| Operating Experience. LRA Section B.2.1.18 summarizes operating experience related to the Fuel Oil Chemistry Program. The staff reviewed this information and interviewed the applicant's technical personnel to confirm that the applicable aging effects and industry and plant
| |
| -specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. During the audit, the staff independently confirmed that the applicant adequately incorporated and evaluated operating experience related to this program.
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| The staff reviewed the following information regarding operating experience:
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| (1) In November 2000, a trend of increasing particulates was identified in diesel generator fuel oil storage tank, 1
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| -DG-TK-26B. Test results from two samples showed particulate matter at 11.8 mg/L and 11.2 mg/L which exceeded the limit of 10 mg/L. As a corrective action, both diesel generator fuel oil storage tanks (1
| |
| -DG-TK-26A and 26B) were filtered to a particulate matter of less than <0.3 mg/L, a condition report was written along with a work order to correct the issue, and a cause analysis was performed. The cause analysis determined that a combination of factors were potential contributors to the high particulate count. Corrective actions included cleaning of the diesel generator day tanks, more frequent replacement of the associated fuel oil filters (every 6 months), reviewing the lube oil
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| -fuel oil interfaces to rule out lube oil contamination of the fuel as a major contributor and planning for future potential particulate clean
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| -up activities. The plant did not experience a loss of intended function of the diesel generator due to the high particulate count.
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| (2) A review of work orders associated with the cleaning and inspection of diesel generator fuel oil storage tanks and day tanks and the fire pump fuel oil day tanks indicate no degradation of the tanks. The "A" diesel generator fuel oil storage tank was drained and the bottom UT inspected in 1994 and 2003. The "B" diesel generator fuel oil storage Aging Management Review Results 3-118 tank was drained and the bottom UT examination was performed on the tank bottom in 1994 and 2005. The "A" diesel generator fuel oil day tank was drained, cleaned and inspected in 2003. The "B" diesel generator fuel oil day tank was drained, cleaned, and inspected in 2005.
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| (3) In June 2001, an inspection of the internal bottom surface of the auxiliary boiler fuel oil storage tank (AB
| |
| -TK-29) was performed by certified personnel under a work order and in accordance with a Seabrook Station specification for cleaning, inspection and repair of the bulk fuel oil storage tank. Inspection results were captured in a technical inspection and engineering analysis report. The report indicated minimal thickness loss on the nominal 1/4" thick floor after 26 years. No degradation of the tank floor was characterized as major.
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| (4) A review of Seabrook Station condition reports identified instances when the new fuel oil deliveries were rejected due to the presence of water. In December of 2004, a fuel shipment for the emergency diesel generators did not meet the acceptance criteria of the clear and bright test. Samples were analyzed for water, particulate, and haze. Visible water droplets could be seen at the bottom of the clear and bright bottle.
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| A second sample was taken, and it also had visible water droplets in the sample bottle and therefore, the tanker fuel oil shipment was rejected. In September 2005, a fuel shipment for the emergency diesel generators did not meet the acceptance criteria for flashpoint. The flashpoint reading of 117°F was below the minimum requirement of 125°F and therefore, the tanker fuel oil shipment was rejected. In these instances, corrective actions were taken to correct the out of specification condition prior to offloading the fuel oil into the diesel generator fuel oil storage tank.
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| (5) Although not discussed in GALL Report AMP XI.M30, the NRC had recently issued Information Notice 2009
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| -02, "Biodiesel in Fuel Oil Could Adversely Impact Diesel Engine Performance." This document indicates that No. 2 diesel fuel could contain up to a 5 percent bio-diesel fuel (B5) blend without labeling the blend in accordance with ASTM D 975-08a, "Standard Specification for Diesel Fuel Oils." Bio
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| -diesel B5 blend: (a) can have a cleansing effect that can increase sediment that could plug filters, (b) could form "dirty water" which leads to algae growth, (c) is biodegradable such that long term storage is not recommended and (d) can be more susceptible to gel creation in the presence of brass, bronze and copper fittings, piping, and tanks. These effects could lead to plant
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| -specific operating experience outside the bounds of industry operating experience. Existing Seabrook Station plant procedures test for bio
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| -diesel prior to offload of fuel oil to the diesel generator fuel oil storage tanks and fire pump fuel oil day tanks. Acceptance criteria for bio
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| -diesel is < 2 percent (non
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| -detectable).
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| The staff reviewed the operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program.
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| During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
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| | |
| Aging Management Review Results 3-119 Based on its audit and review of the application, the staff finds that the operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking appropriate corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
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| UFSAR Supplement. LRA Section A.2.1.18 provides the UFSAR supplement for the Fuel Oil Chemistry Program. The staff reviewed the UFSAR supplement description of the program against the recommended description for this type of program as described in SRP
| |
| -LR Table 3.3-2. The staff found that the description of the Fuel Oil Chemistry Program, as described in LRA Section A.2.1.18, does not indicate which ASTM standards the program implements but simply states the program will use the applicable ASTM standards. The example description for this program in SRP
| |
| -LR Table 3.3-2 includes specific mention of ASTM Standards D1796, D4057, D2709, and D2276. The licensing basis for the period of extended operation may not be adequate if the applicant does not incorporate this information in its UFSAR supplement.
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| By letter dated December 14, 2010, the staff issued RAI B.2.1.18
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| -1, requesting that the applicant justify why it did not include the referenced ASTM standards. In its response dated January 13, 2011, the applicant amended the UFSAR supplement in LRA Section A.2.1.18. The amended UFSAR supplement states the following:
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| New fuel oil is sampled and verified to meet the requirements of applicable American Society for Testing and Materials (ASTM) standards D4057 and D2709 prior to offloading to the storage tanks. Stored fuel oil is sampled and verified to meet the requirements of ASTM D2276 or ASTM D4057, and ASTM D2709. The program monitors fuel oil quality and levels of water in the fuel oil which may cause the loss of material of the tank internal surfaces. The program monitors water and sediment contamination in diesel fuel.
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| The applicant also amended the program with the submittals of March 5, 2014, and March 9, 2015. With these amendments, the staff finds the UFSAR supplement for the Fuel Oil Chemistry Program acceptable because it is consistent with the corresponding program description in SRP
| |
| -LR Table 3.3
| |
| -2. The staff's concern described in RAI B.2.1.18
| |
| -1 is resolved. The staff's evaluation of the UFSAR supplement for the Fuel Oil Chemistry Program addressing loss of coating integrity is documented in SER Section 3.0.3.4.1.
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| The staff also noted that the applicant committed (Commitment Nos. 14, 15, 16, 17, 58, and 81) to enhancing the Fuel Oil Chemistry Program within 10 years prior to the period of extend ed operation. Specifically, the applicant committed to do the following:
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| (1) Enhance program to add requirements to (1) sample and analyze new fuel deliveries for biodiesel prior to offloading to the auxiliary boiler fuel oil storage tank and (2) periodicall y sample stored fuel in the auxiliary boiler fuel oil storage tank.
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| (2) Enhance the program to add requirements to check for the presence of water in the auxiliary boiler fuel oil storage tank at least once per quarter and to remove water as necessary.
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| (3) Enhance the program to require draining, cleaning and inspection of the diesel fire pump fuel oil day tanks on a frequency of at least once every 10 years.
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| | |
| Aging Management Review Results 3-120 (4) Enhance the program to require ultrasonic thickness measurement of the tank bottom during the 10
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| -year draining, cleaning and inspection of the diesel generator fuel oil storage tanks, diesel generator fuel oil day tanks, diesel fire pump fuel oil day tanks and auxiliary boiler fuel oil storage tank.
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| (5) Update Technical Requirement Program 5.1, (Diesel Fuel Oil Testing Program) ASTM standards to ASTM D2709
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| -96 and ASTM D4057
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| -95 required by GALL Report AMP XI.M30, Revision 1.
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| (6) Enhance the program to address loss of coating integrity.
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| The staff determined that the information in the UFSAR supplement, as amended, is an adequate summary description of the program, as required by 10 CFR 54.21(d).
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| Conclusion. On the basis of its audit and review of the applicant's Fuel Oil Chemistry Program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exceptions and their justifications and determined that the AMP, with the exceptions, is adequate to manage the aging effects for which the LRA credits it. Also, the staff reviewed the enhancements and confirmed that their implementation through Commitment Nos. 14, 15, 16, 17, 58, and 81, prior to the period of extended operation (the Fuel Oil Chemistry Program within 10 years prior to the period of extended operation), would make the existing AMP consistent with the GALL Report AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
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| 3.0.3.2.11 Reactor Vessel Surveillance Program Summary of Technical Information in the Application. LRA Section B.2.1.19 describes the existing Reactor Vessel Surveillance Program as consistent, with enhancements, with GALL Report AMP XI.M31," Reactor Vessel Surveillance." The applicant included the following four enhancements:
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| (1) The program will specify that all pulled and tested capsules, unless discarded before August 31, 2000, are placed in storage (Criterion 1).
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| (2) The program will specify that if plant operations exceed the bounds defined by the RV Surveillance Program, such as operating at a lower cold leg temperature or higher fluence, the impact of plant operation changes on the extent of reactor vessel embrittlement will be evaluated, and the NRC will be notified (Criterion 1).
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| (3) The program will ensure the appropriate withdrawal schedule for capsules remaining in the vessel such that one capsule will be withdrawn at an outage in which the capsule receives a neutron fluence that meets the regulatory requirements and that bounds the 60-year fluence. The remaining capsule(s) will be removed from the vessel unless determined to provide meaningful metallurgical data (Criterion 5).
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| (4) The program will ensure that any capsule removed without testing will be stored in a manner that maintains it in a condition, which would permit its future use, including during the period of extended operation (Criterion 5).
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| | |
| Aging Management Review Results 3-121 With these enhancements, the applicant stated that the existing Reactor Vessel Surveillance Program will provide reasonable assurance that loss of fracture toughness due to neutron irradiation embrittlement will be adequately managed so that the intended functions of components within the scope of license renewal will be maintained consistent with the CLB during the period of extended operation.
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| Staff Evaluation. Appendix H of 10 CFR Part 50 specifies surveillance program criteria for 40 years of operation. GALL Report AMP XI.M31 specifies additional criteria for 60 years of operation. The staff determined that compliance with 10 CFR Part 50, Appendix H, criteria for capsule design, location, specimens, test procedures, and reporting remains appropriate for this Seabrook AMP because these items, which satisfy 10 CFR Part 50, Appendix H, will stay the same throughout the period of extended operation.
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| The 10 CFR Part 50, Appendix H, capsule withdrawal schedule during the period of extended operation is addressed in accordance with the Section XI.M31 consideration of eight criteria for an acceptable reactor pressure vessel (RPV) surveillance program for 60 years of operation.
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| The staff reviewed LRA B.2.1.19 with its four enhancements and the associated justifications to determine if the AMP is adequate to manage the aging effects for which it is credited. The enhancements address three of the eight AMP acceptance criteria (Criteria 3, 4, and 6) in GALL Report AMP XI.M31.
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| Enhancement 1. LRA Section B.2.1.19 states an enhancement to the program related to Criterion 4 in the GALL Report AMP XI.M31. The enhancement describes the storage requirements and the need to retain future pulled capsules. This enhancement meets the fourth criterion of GALL Report AMP XI.M31 and will keep used surveillance specimens for future use.
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| Enhancement 2. LRA Section B.2.1.19 states an enhancement to the program related to Criterion 3 in the GALL Report AMP XI.M31. The enhancement limits the RPV cold leg temperature and neutron fluence projections. This enhancement meets the third criterion of GALL Report AMP XI.M31 and will increase the quality of the surveillance data.
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| Enhancement 3. LRA Section B.2.1.19 states an enhancement to the program related to Criterion 6 in the GALL Report AMP XI.M31. The enhancement specifies capsule withdrawal schedule, meeting the sixth criterion of GALL Report AMP XI.M31 because the surveillance program consists of capsules with a projected fluence exceeding the 60
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| -year fluence at the end of 40 years. The Seabrook Reactor Vessel Surveillance Program will withdraw one of the remaining capsules at an outage in which the capsule receives a neutron fluence that meets the schedule requirements of 10 CFR Part 50 Appendix H and ASTM E185
| |
| -82 and that bounds the 60-year fluence and test that capsule in accordance with the requirements of ASTM E185
| |
| -82. Enhancement 4. LRA Section B.2.1.19 states an enhancement to the program related to Criterion 6 in the GALL Report AMP XI.M31. The enhancement incorporates the requirements for withdrawing the remaining capsules and placing them in storage when the monitor capsule is withdrawn during the period of extended operation. This enhancement also meets the second part of the sixth criterion of GALL Report AMP XI.M31 and makes reinstituting an RPV Surveillance Program achievable under conditions such as change of the exposure conditions of the RPV.
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| The staff's review of this Seabrook AMP against the remaining criteria is discussed below.
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| | |
| Aging Management Review Results 3-122 Criteria 1 and 2 of GALL Report AMP XI.M31 regard evaluation of the 60
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| -year upper
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| -shelf energy (USE) and pressure
| |
| -temperature (P
| |
| -T) limits, using RG 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel Materials." LRA Section B.2.1.19 states that Seabrook has documented the extent of embrittlement for USE and P
| |
| -T limits for 60 years (55 effective full power years (EFPYs)), in accordance with RG 1.99, Revision 2, using both the chemistry tables and existing surveillance data as applicable. LRA Section B.2.1.19 further states that surveillance capsule data from all capsules withdrawn to date was used to obtain the relationship between the mean value of nil
| |
| -ductility reference temperature (RT NDT) change due to fluence as discussed in Position 2.1 of RG 1.99, Revision 2. Since the Seabrook AMP evaluates the 60
| |
| -year USE and P
| |
| -T limits fully in accordance with RG 1.99, Revision 2, including the limitations specified in Criterion 2, Criteria 1 and 2 are satisfied.
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| Criterion 5 (for plants with a surveillance program that consists of capsules with a projected fluence of less than the 60
| |
| -year fluence at the end of 40 years) and Criterion 7 (for plants not having surveillance capsules) do not apply to the Seabrook AMP.
| |
| Criterion 8 asks for justification for not including nozzle specimens in the surveillance program. The applicant did not address this issue explicitly in LRA Section B.2.1.19. However, this item was addressed indirectly in Section 4.2.3 of the LRA in which the applicant does not include nozzle materials that will not exceed the surface fluence value of 1.0x10 17 neutrons per square centimeter (n/cm 2)(E > 1.0 MeV) at 55 EFPYs. The staff finds that Criterion 8 is satisfied. The staff's evaluation of the RPV beltline and extended beltline materials for the period of extended operation meeting the requirements of 10 CFR 54.21(c)(1)(ii), in which the analyses have been projected for 60 years of operation, is documented in SER Section 4.2.3.
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| Based on its audit and review of the application, the staff finds that the eight criteria of the applicant's Reactor Vessel Surveillance Program, with acceptable enhancements, are consistent with the corresponding program elements of GALL Report AMP XI.M31 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.19 summarizes operating experience related to the Reactor Vessel Surveillance Program. The applicant cited evaluation results of three surveillance capsules withdrawn from 1991
| |
| -2005 to conclude that the materials met the requirements for continued safe operation. The cited evaluation results provide evidence that the existing Reactor Vessel Surveillance Program will be capable of monitoring the aging effects associated with the loss of fracture toughness due to neutron irradiation embrittlement of the RPV beltline materials. The staff concurred with the applicant's conclusion, as supported by the staff's approval of the current pressurized thermal shock evaluation and P
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| -T limits, using information from all surveillance data in accordance with RG 1.99, Revision 2.
| |
| Furthermore, the applicant demonstrated that the plant responded to industry operating experience related to damage that another similar facility found in the lower internals support flange and the surveillance capsule access plug in the lower internals flange. The applicant conducted an underwater
| |
| -camera visual inspection to document that similar damage had not occurred at Seabrook.
| |
| The staff reviewed operating experience information in the application to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant and are evaluated in the GALL Report. During its review, the staff found no Aging Management Review Results 3-123 operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that the operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking appropriate corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. The applicant provided its UFSAR supplement for the Reactor Vessel Surveillance Program in LRA Section A.2.1.19.
| |
| The staff also noted that the applicant committed (Commitment Nos. 18
| |
| -21) to implement the existing Reactor Vessel Surveillance Program with the enhancements listed below prior to entering the period of extended operation:
| |
| * The applicant will specify that all pulled and tested capsules, unless discarded before August 31, 2000, are placed in storage.
| |
| * The applicant will specify that if plant operations exceed the limitations or bounds defined by the Reactor Vessel Surveillance Program, such as operating at a lower cold leg temperature or higher fluence, the impact of plant operation changes on the extent of reactor vessel embrittlement will be evaluated, and the NRC will be notified.
| |
| * The applicant will ensure the appropriate withdrawal schedule for capsules remaining in the vessel, such that one capsule will be withdrawn at an outage in which the capsul e receives a neutron fluence that meets the schedule requirements of 10 CFR Part 50, Appendix H, and ASTM E185
| |
| -82 and that bounds the 60
| |
| -year fluence. The remaining capsules(s) will be removed from the vessel unless determined to provide meaningful metallurgical data.
| |
| * The applicant will ensure that any capsule removed, without the intent to test it, is stored in a manner that maintains it in a condition that would permit its future use, including during the period of extended operation.
| |
| The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its review of the applicant's Reactor Vessel Surveillance Program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that their implementation prior to the period of extended operation supports the requirements of the AMP. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.2.12 Selective Leaching of Materials Program
| |
| | |
| Aging Management Review Results 3-124 Summary of Technical Information in the Application. LRA Section B.2.1.21 describes the new Selective Leaching of Materials Program as consistent, with an exception, with GALL Report AMP XI.M33, "Selective Leaching of Materials." The applicant stated that the Selective Leaching of Materials Program will manage the aging effect of loss of material due to selective leaching in gray cast iron, copper alloys greater than 8
| |
| -percent aluminum (e.g., aluminum
| |
| -bronze) and copper alloy (greater than 15
| |
| -percent zinc) exposed to raw water, brackish water, treated water (including closed
| |
| -cycle cooling), or groundwater.
| |
| The applicant also stated that the program will use one
| |
| -time visual inspections and mechanical test techniques such as chipping, scraping, or hardness testing to determine if selective leaching is occurring. The applicant further stated that inspections will include a representative sample of the most susceptible locations selected from each material and environment combination with a sample size of 20 percent, not to exceed a sample size of 25 components. The applicant stated that if evidence of selective leaching is discovered, it will perform an engineering evaluation to determine acceptability of the affected components for continued service and implement an expansion of the inspection sample size and location.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.M33. As discussed in the audit report, the staff confirmed that each element of the applicant's program is consistent with the corresponding element of GALL Report AMP XI.M33, with the exception of the "scope of program," "parameters monitored or inspected" and "detection of aging effects" program elements. For these elements, the staff determined the need for additional clarification, which resulted in the issuance of RAIs.
| |
| GALL Report AMP XI.M33 recommends a possible expansion of the inspection sample size and location if selective leaching is detected under the "parameters monitored or inspected" program element description. The "detection of aging effects" program element description also recommends the initiation of an engineering evaluation to determine the acceptability of the affected components if selective leaching has occurred. LRA Section B.2.1.21 states that Seabrook has experienced instances of de
| |
| -aluminization of aluminum bronze components having an internal environment of raw seawater. Given that selective leaching of aluminum
| |
| -bronze components has occurred, it is unclear how an expansion of the inspection sample sizes and locations are being implemented. By letter dated November 18, 2010, the staff issued RAI B.2.1.21-1, requesting that the applicant clarify if the Selective Leaching of Materials Program has implemented an expansion of the inspection sample size and location for aluminum bronze components given that selective leaching has occurred. The staff asked the applicant to describe the methodology and criteria for selecting a representative sample population that envelopes all plant systems and working conditions at locations most susceptible to selective leaching. If the expansion has not been implemented, the applicant was asked to describe any planned inspection and associated activities ahead and to justify the methodology, sample size, and location used for selecting components with different material and environment combinations for selective leaching inspections.
| |
| In its response dated December 17, 2010, the applicant stated that the Selective Leaching of Materials Program had been revised to expand the inspection sample size and location for Aging Management Review Results 3-125 aluminum-bronze components upon discovery of unacceptable inspection results. The revised program includes a one
| |
| -time inspection of selected components where selective leaching has not been previously identified and periodic inspections of selected components where selective leaching has been identified. The applicant further stated that both visual and mechanical examination techniques (Brinell hardness testing or other mechanical examination techniques such as destructive testing, when appropriate, scraping, chipping, or other types of hardness testing) would be used to determine if selective leaching is occurring. The applicant further stated that an initial inspection of the aluminum bronze components of a sample size of 20 percent of the population with a maximum of 25 locations would be performed within 5 years prior to entering the period of extended operation. The selection of locations will consider time in service, severity of operating conditions, lowest design margin, and distribution of susceptible components across systems within similar material and environment combinations. The applicant further stated that followup of unacceptable inspection findings would include an evaluation using the corrective action program and a possible expansion of the inspection size and location. The applicant also stated that it has previously identified selective leaching in aluminum bronze components in raw water; therefore, all in-scope aluminum bronze components in a raw water environment will be grouped separately from other copper
| |
| -alloy (greater than 15
| |
| -percent zinc) components and be inspected periodically.
| |
| The staff finds the applicant's response acceptable because the applicant's revised Selective Leaching of Materials Program is consistent with the GALL Report AMP XI.M33 recommendation of performing a one
| |
| -time visual inspection of selected components susceptible to selective leaching, coupled with either hardness measurements or mechanical examination techniques. In addition, the staff noted that the applicant's inspection selection criteria and methodology align with the GALL Report recommendation of 20 percent of the population with a maximum sample of 25 be in a representative sample. The staff's concern described in RAI B.2.1.21-1 is resolved.
| |
| The staff noted that LRA Tables 3.4.2
| |
| -1 and 3.4.2
| |
| -3 list components made of gray cast iron and copper alloy (great than 15 percent zinc) that are exposed to steam (internal), which is not included in the B.2.1.21 program description. By letter dated January 21, 2011, the staff issued RAI B.2.1.21
| |
| -2, requesting that the applicant clarify whether steam (internal) is an environment for the Selective Leaching Materials Program.
| |
| In its response dated February 18, 2011, the applicant stated that steam is regarded as a form of treated water and is an environment applicable to selective leaching. The applicant further stated that it had revised the scope of LRA Section B.2.1.21 to include steam as one of the environments applicable to selective leaching.
| |
| The staff finds the applicant's response acceptable because the scope of the Selective Leaching of Materials Program has been expanded to envelope steam as one of the environments applicable to selective leaching, which aligns the program description of this AMP with the components in LRA Tables 3.4.2
| |
| -1 and 3.4.2
| |
| -3. The staff's concern described in RAI B.2.1.21-2 is resolved.
| |
| The staff also reviewed the portion of the "detection of aging effects" program element associated with the exception to determine if the program will be adequate to manage the aging effects for which it is credited. The staff's evaluation of this exception follows.
| |
| | |
| Aging Management Review Results 3-126 Exception 1. LRA Section B.2.1.21 states an exception to the "detection of aging effects" program element. The GALL Report recommends visual inspections of the susceptible components and Brinell hardness testing on the inside surfaces of the selected set of components to determine if selective leaching has occurred. The applicant stated that it will use visual inspections and mechanical examination techniques, including Brinell hardness testing or other mechanical examination techniques such as scraping, chipping, or other types of hardness testing, or additional examination methods that become available to the nuclear industry, to determine if selective leaching is occurring on the surfaces of a selected set of components.
| |
| The staff reviewed this exception to the GALL Report and noted that the applicant took the exception because the form and configuration of many components do not physically allow access for Brinell hardness testing and that additional mechanical testing techniques are needed. The staff finds the program's exception acceptable because the mechanical examination techniques proposed by the applicant, such as scraping, chipping, or other types of hardness testing, are capable to detecting the aging effect of loss of material due to selective leaching.
| |
| Regarding the additional examination methods that will become available, the staff does not have sufficient information to evaluate the effectiveness of such methods. By letter dated January 21, 2011, the staff issued RAI B.2.1.
| |
| 21-3, requesting that the applicant state how the new process would be evaluated and qualified to detect selective leaching of material on the surfaces in components made of gray cast iron and copper alloys greater than 15 percent zinc exposed to the environment of interest.
| |
| In its response dated February 18, 2011, the applicant stated that the statement "additional examination methods that become available to the nuclear industry" was included in the LRA in anticipation of new technologies that may be available prior to the implementation of this AMP. The applicant further stated that this statement had been removed from the LRA in response to this RAI.
| |
| The staff finds the applicant's response acceptable because deletion of such statement removes ambiguity from this AMP. The staff noted that the revised program description (i.e., visual examination and mechanical examination techniques (Brinell hardness testing or other mechanical examination techniques such as destructive testing, when appropriate, scraping, chipping, or other types of hardness testing)) is consistent with the GALL Report AMP XI.M33 Selective Leaching of Materials recommendation of a one
| |
| -time visual examination and hardness measurement of sample components. The staff's concern described in RAI B.2.1.21
| |
| -3 is resolved.
| |
| Based on its audit, review of the application, and review of the applicant's response to RAIs B.2.1.21-1, B.2.1.21
| |
| -2, and B.2.1.21
| |
| -3, the staff finds that elements one through six of the applicant's Selective Leaching of Materials Program, with acceptable exception, are consistent with the corresponding program elements of GALL Report AMP XI.M33 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.21 summarizes operating experience related to the Selective Leaching of Materials Program. The applicant stated that de
| |
| -aluminization of aluminum-bronze pipe fittings, flanges, and unions exposed to raw seawater has occurred. The applicant also stated that appropriate corrective actions had been taken to replace the Aging Management Review Results 3-12 7 aluminum-bronze fittings with copper
| |
| -nickel components for the piping systems. The applicant further stated that plant
| |
| -specific guidance for evaluation, repair, or replacement is provided for locations where de
| |
| -aluminization was found.
| |
| The staff reviewed operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program.
| |
| During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.21 provides the UFSAR supplement for the Selective Leaching of Materials Program. The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program as described in SRP
| |
| -LR Tables 3.1
| |
| -2, 3.2-2, and 3.3
| |
| -2. The staff also noted that the applicant committed (Commitment 23) to implement the new Selective Leaching of Materials Program for managing aging of applicable components within 5 years prior to the period of extended operation, as stated in the applicant's supplement 2 to its LRA dated November 15, 2010.
| |
| The staff noted that the applicant did not include the recommended description in the SRP
| |
| -LR, which states, "[f]or systems subjected to environments where water is not treated (i.e., the open-cycle cooling water system and the ultimate heat sink), the program also follows the guidance in NRC GL 89
| |
| -13." However, the staff noted that LRA Sections B.2.1.11 and A.2.1.11 state that the Open
| |
| -Cycle Cooling Water System Program relies on the recommendations of NRC GL 89-13. The staff finds the applicant's commitment to GL 89
| |
| -13 in its Open
| |
| -Cycle Cooling Water System Program sufficient to ensure that the aging effects of selective leaching will be adequately managed.
| |
| The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its audit and review of the applicant's Selective Leaching of Materials Program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and its justification and determined that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended Aging Management Review Results 3-128 function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.2.13 One
| |
| -Time Inspection of ASME Code Class 1 Small
| |
| -Bore Piping Summary of Technical Information in the Application. LRA Section B.2.1.23 describes the new One-Time Inspection of ASME Code Class 1 Small
| |
| -Bore Piping Program as consistent, with an exception, with GALL Report AMP XI.M35, "One
| |
| -Time Inspection of ASME Code Class 1 Small Bore Piping." The applicant stated that this new program will manage the aging effects of cracking in stainless steel small
| |
| -bore ASME Code Class 1 piping less than 4 in. nominal pipe size (NPS). The applicant further stated that cracking due to SCC, thermal fatigue, and mechanical fatigue will be identified by performing volumetric examinations. The applicant stated that it will select a sample from the total population of ASME Code Class 1 piping based on susceptibility, inspectability, dose considerations, operating experience, and limiting locations as recommended in Materials Reliability Program (MRP)
| |
| -146, "Materials Reliability Program: Management of Thermal Fatigue in Normally Stagnant Non
| |
| -Isolable Reactor Coolant System Branch Lines." The applicant also stated that this sample population will include both butt and socket welds and that, if non
| |
| -destructive volumetric inspection techniques have not been qualified, it will have the option to remove the weld for destructive examination. The applicant further stated that cracking of small-bore ASME Code Class 1 piping has not been observed.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.M35. As discussed in the audit report, the staff confirmed that each element of the applicant's program is consistent with the corresponding element of GALL Report AMP XI.M35, with the exception of the "monitoring and trending" program element. For this element, the staff determined the need for additional clarification, whic h resulted in the issuance of an RAI.
| |
| GALL Report AMP XI.M35 recommends that a one
| |
| -time volumetric inspection is an acceptable method for confirming the absence of cracking in ASME Code Class 1 small
| |
| -bore piping. The GALL Report also states that the inspection of small
| |
| -bore piping should be performed at a sufficient number of locations to ensure an adequate sample. The GALL Report further states that this number, or sample size, will be based on susceptibility, inspectability, dose considerations, operating experience, and limiting locations of the total population of ASME Code Class 1 small
| |
| -bore pipes. Furthermore, MRP
| |
| -146 provides guidelines for identifying piping susceptible to one subset of cracking, including thermal stratification or turbulent penetrations. During its audit, the staff found that the applicant will inspect for cracking in ASME Code Class 1 small
| |
| -bore piping using available volumetric examination techniques. The applicant also stated that if non
| |
| -destructive volumetric examination techniques have not been qualified, it will have the option to remove the weld for destructive examination. Furthermore, the applicant stated during the onsite audit that it will inspect 10 percent of the butt welds and 10 percent of the socket welds and that it may not inspect certain welds based on inaccessibility or high radiation exposure.
| |
| | |
| Aging Management Review Results 3-129 It was not clear to the staff if the applicant will either conduct an acceptable volumetric inspection or plan to do destructive examination based on the applicant's program basis document, which states that if an acceptable volumetric examination is not available before the period of extended operation, the applicant will have a choice to do destructive examinations. In addition, it is not clear to the staff if the applicant is proposing to inspect weld locations that are mainly susceptible to thermal loading because the applicant's sampling methodology for the inspection was not presented. It was also not clear to the staff what area (base metal or weld metal) of the socket weld the examination would inspect. By letter dated December 14, 2010, the staff issued RAI B.2.1.23
| |
| -1, requesting that the applicant do the following:
| |
| * clarify how the use of destructive examination is an "option" within the program and UFSAR supplement if an "acceptable" volumetric method is not available
| |
| * clarify what is meant by an "acceptable" volumetric inspection
| |
| * describe the methodology for choosing the types of welds to inspect and how this methodology will ensure the AMP adequately manages the effects of all forms of cracking during the period of extended operation
| |
| * explain how inaccessible or high radiation exposure welds will be managed by the AMP
| |
| * clarify the proposed volumetric examination for socket welds
| |
| * justify that the examination volume is sufficient and capable of detecting cracking in the subject socket welds In its response dated January 13, 2011, the applicant replied to all the parts of the request. The applicant stated that, as a way to clarify the use of the word "optional," the program has been modified to specify that, if no demonstrated method of non
| |
| -destructive volumetric examination capable of detecting cracking in a socket weld is available, the applicant will remove selected weld(s) for destructive examination. The staff finds that a destructive examination is an acceptable alternative because it will provide direct evidence whether aging is occurring when compared to a no n-destructive examination. The applicant stated that it modified the program to state that the volumetric inspection technique to be used should be "demonstrated" to have the capability of detecting cracking. The applicant stated that approximately 450 ASME Code Class 1 small
| |
| -bore welds have been identified and approximately 150 of these are socket welds. The applicant further stated that its inspection will include at least 10 percent of the total number of these welds. The applicant also stated that it modified its One
| |
| -Time Inspection of ASME Code Class 1 Small
| |
| -Bore Piping Program to state that the sample selection will give priority to locations determined to be most susceptible to SCC and to cycling loading (including thermal, mechanical, and vibrational fatigue). The applicant stated that, for specific locations that are not selected because of accessibility or radiation exposures, a location with similar susceptibility will be identified to replace it in the sample selection. The staff finds that the inspection of one location to be representative of another location that is not accessible or has a higher radiation exposure is an acceptable technique because the surrogate inspection, with the same susceptibility to aging, will provide comparable results. Finally, the applicant stated that socket welds will be examined to the maximum extent possible using methods demonstrated to detect cracking in socket welds. The applicant stated that the target of the socket weld will be the weld and not the piping downstream, as described in MRP
| |
| -146. Based on its review, the staff finds the applicant's response to RAI B.2.1.23
| |
| -1 acceptable because the applicant's modifications to the program, as described above, will evaluate an Aging Management Review Results 3-130 adequate number of welds to manage cracking with either a demonstrated non
| |
| -destructive volumetric examination or destructive examination, which makes the applicant's program consistent with the GALL Report AMP XI.M35. The staff's concern described in RAI B.2.1.23
| |
| -1 is resolved.
| |
| The staff also reviewed the portions of the "scope of program" program element associated with an exception to determine if the program will be adequate to manage the aging effects for which it is credited. The staff's evaluation of this exception follows.
| |
| Exception 1. LRA Section B.2.1.23 states an exception to the "scope of program" program element. The applicant stated that it plans to use the guidance in MRP
| |
| -146, "Materials Reliability Program: Management of Thermal Fatigue in Normally Stagnant Non
| |
| -Isolable Reactor Coolant System Branch Lines," and supplemental guidance in MRP
| |
| -146-S, "Materials Reliability Program: Management of Thermal Fatigue in Normally Stagnant Non
| |
| -Isolable Reactor Coolant System Branch Lines
| |
| -Supplemental Guidance," to identify piping susceptible to potential effects of thermal stratification or turbulent penetration.
| |
| The staff reviewed the "scope of program" program element of GALL Report AMP XI.M35, which states that the program should include measures to verify that degradation does not occur for ASME Code Class 1 small
| |
| -bore piping in components susceptible to cracking. The "scope of program" program element also states that locations that are susceptible to thermal stratification or turbulent penetration can be determined by MRP
| |
| -24, "Interim Thermal Fatigue Management Guideline." The staff noted that MRP
| |
| -24 was an interim report that was meant to provide early feedback to PWR plant operators and that this report was later updated in MRP
| |
| -146 and MRP
| |
| -146-S to expand on the interim guidelines and provide updated information.
| |
| Based on its review, the staff finds the program exception acceptable because the applicant is using updated reports, which expand upon the interim guidelines provided in MRP
| |
| -24 by incorporating technical knowledge gained from thermal
| |
| -hydraulic testing and model development, which will provide improved guidance on identifying locations susceptible to cracking from thermal fatigue.
| |
| Based on its audit, review of the application, and review of the applicant's response to RAI B.2.1.23
| |
| -1, the staff finds that elements one through six of the applicant's One
| |
| -Time Inspection of ASME Code Class 1 Small
| |
| -Bore Piping Program, with an acceptable exception, are consistent with the corresponding program elements of GALL Report AMP XI.M35 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.23 summarizes operating experience related to the One-Time Inspection of ASME Code Class 1 Small
| |
| -Bore Piping Program. The applicant stated that this is a new program and that both plant and industrial operating experience will be used to establish the program. The applicant further stated that during its second 10
| |
| -year ISI period, the inspections included volumetric examination of twenty
| |
| -seven 2-in. and 3-in. Class 1 butt welds with no cracking being identified. The applicant also stated that it conducted a search of condition reports and did not find degradation or failure in any Class 1 piping less than 4 in. NPS. The staff reviewed operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the Aging Management Review Results 3-131 audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program. During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking appropriate corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.1.2.23 provides the UFSAR supplement for the One
| |
| -Time Inspection of ASME Code Class 1 Small
| |
| -Bore Piping Program.
| |
| The staff reviewed this UFSAR supplement description of the program against the recommended description for this type of program, as described in SRP
| |
| -LR Table 3.1
| |
| -2. The staff also noted that the applicant committed (Commitment 25) to implement the new One
| |
| -Time Inspection of ASME Code Class 1 Small
| |
| -Bore Piping Program within 10 years prior to the period of extended operation for managing aging of applicable components.
| |
| The staff determined that the information in the UFSAR supplement, as amended, is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its audit and review of the applicant's One
| |
| -Time Inspection of ASME Code Class 1 Small
| |
| -Bore Piping, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and its justification and determined that the AMP, with an acceptable exception, is adequate to manage the aging effects for which the LRA credits it. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.2.14 External Surfaces Monitoring Program Summary of Technical Information in the Applicatio
| |
| : n. LRA Section B.2.1.24 describes the existing External Surfaces Monitoring Program as consistent, with exceptions and an enhancement, with GALL Report AMP XI.M36, "External Surfaces Monitoring." The applicant stated that the program manages the following aging effects:
| |
| * hardening and loss of strength due to elastomer degradation
| |
| * reduction of heat transfer due to fouling
| |
| * loss of material due to general, pitting, crevice, galvanic, and microbiologically
| |
| -influenced corrosion and due to fouling
| |
| * loss of material due to wear
| |
| | |
| Aging Management Review Results 3-132 The applicant also stated that the program consists of periodic inspections of components made of aluminum, cast austenitic stainless steel (CASS), copper alloy, copper alloy with greater than 15 percent zinc, elastomer, galvanized steel, gray cast iron, nickel
| |
| -alloy, stainless steel, and steel. The applicant further stated that this program uses periodic inspections and walkdowns to monitor material degradation and leakage. In addition, the applicant stated that it conducts visual inspection of component surfaces at least once per refueling cycle.
| |
| During the course of the staff's review, the applicant submitted amendments to the application, and these are discussed in the staff's evaluation below, as appropriate.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.M36. As discussed in the audit report, the staff confirmed that each element of the applicant's program is consistent with the corresponding element o f GALL Report AMP XI.M36, with the exception of the "monitoring and trending" program element. For this element, the staff determined the need for additional clarification, which resulted in the issuance of an RAI.
| |
| GALL Report AMP XI.M36 recommends periodic plant system inspections and walkdowns to monitor for material degradation under the "monitoring or trending" program element description; however, during the onsite audit, staff identified that the applicant's AMP has in
| |
| -scope components that cannot be reached for hands
| |
| -on inspection and, therefore, are not accessible for the tactile inspection as described in the LRA. By letter dated November 18, 2010 (ADAMS Accession No. ML103090308), the staff issued RAI B.2.1.24
| |
| -1, requesting that the applicant provide information as to how the tactile techniques would be applied for the in
| |
| -scope components that are inaccessible for physical manipulation. In its response dated December 17, 2010 (ADAMS Accession No. ML103540534), the applicant stated that when an elastomer is inaccessible for tactile inspection, the tactile inspection results of an accessible elastomer of the same construction, in a similar environment, with an equivalent age will be used to assess the condition of the inaccessible elastomer. The applicant also stated that it will apply the same method for determining the condition of metallic components that are inaccessible for visual inspection.
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| The staff finds the applicant's response acceptable because visual and tactile inspections are capable of identifying the aging effects managed by the program prior to loss of intended function. Also, inspection of accessible components with similar construction, age, and environment to those of inaccessible components is an acceptable method to project the condition of components with similar construction, age, and environment that cannot be inspected because they are inaccessible. The staff noted that this is an acceptable method used to assess the effects of aging for inaccessible components in other AMPs in the GALL Report. The staff's concern described in RAI B.2.1.24
| |
| -1 is resolved.
| |
| The staff also reviewed the portions of the "scope of program," "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements associated with exceptions and enhancements to determine if the program Aging Management Review Results 3-133 will be adequate to manage the aging effects for which it is credited. The staff's evaluation of these exceptions and enhancements follows.
| |
| Exception 1. LRA Section B.2.1.24 states an exception to the "scope of program" program element. The applicant stated that its program will manage aging of components made from additional materials such as aluminum, CASS, copper alloy, copper alloy with greater than 15 percent zinc, elastomer, galvanized steel, gray cast iron, nickel alloy, and stainless steel whereas the GALL Report recommends the program for steel components.
| |
| The staff reviewed this exception to the GALL Report and noted that the applicant took the exception because additional materials are to be covered in the applicant's AMP, which are beyond those recommended by the GALL Report. The staff evaluated the exception and determined the need for additional clarification, which resulted in the issuance of an RAI. GALL Report AMP XI.M36 states that the program consists of periodic visual inspections of steel components such as piping, piping components, ducting, and other components within the scope of license renewal under the "Program Description." However, the applicant indicated that the program will be applied to materials other than steel, which is the material specified in GALL Report for this AMP. By letter dated November 18, 2010 (ADAMS Accession No. ML103090308), the staff issued RAI B.2.1.24
| |
| -2, requesting that the applicant provide details on additional inspection methods to be used to ensure that the AMP will adequately address potential aging effects on the additional in
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| -scope materials.
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| In its response dated December 17, 2010 (ADAMS Accession No. ML103540534), the applicant stated that the nuclear industry has developed programs to train plant staff on how to correlat e an observed condition with possible aging effects. The applicant also stated that personnel who perform inspections as part of the implemented license renewal program will be trained and qualified to identify aging effects in the additional in
| |
| -scope materials. The applicant's response did not identify any additional inspection methods necessary to manage the aging effects for the additional in
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| -scope materials because the External Surfaces Monitoring Program includes visual inspections of metallic components and visual inspections and tactile examinations of elastomeric components. The staff noted that visual inspection is an appropriate inspection method for detecting loss of material in metallic components and cracking due to SCC in stainless steel components exposed to outdoor air. The staff also noted that visual inspections coupled with tactile examinations are capable of detecting loss of material, hardening, and loss of strength in flexible elastomeric components.
| |
| The staff finds the applicant's response acceptable because the visual inspections and tactile examinations performed as part of the External Surfaces Monitoring Program are capable of detecting the applicable aging effects for the metallic and elastomeric components in the scope of the program, and the personnel performing the inspections will be trained and qualified to identify the aging effects in the additional materials. The staff's concern described in RAI B.2.1.24-2 is resolved.
| |
| Exception 2. LRA Section B.2.1.24 states an exception to the "scope of program" and "detection of aging effects" program elements. The applicant stated that the program will address the additional aging effects of hardening and loss of strength, reduction of heat transfer, and loss of material due to galvanic corrosion and wear, whereas the GALL Report recommends this program for managing the aging effect of loss of material.
| |
| | |
| Aging Management Review Results 3-134 The staff reviewed this exception to the GALL Report and noted that the applicant took the exception because additional aging effects are to be covered in the applicant's AMP, which are beyond those recommended by the GALL Report. The staff evaluated the exception and determined that the exception is adequate because the additional aging effects being managed by the program are addressed with corresponding inspection methods. Specifically, the use of tactile inspection methods will be used to address the additional aging effects being managed for the in
| |
| -scope elastomers. Additionally, the aging effects of hardening and loss of strength, reduction of heat transfer, and loss of material due to galvanic corrosion on the in
| |
| -scope metallic components will be adequately covered by the visual inspections included in the program. Enhancement 1. LRA Section B.2.1.24 states an enhancement to the "scope of program," "parameters monitored or inspected," "monitoring and trending," and "acceptance criteria" program elements. The applicant stated that the AMP will be enhanced to more specifically address the relevant degradation mechanisms and aging effects, and the inspections will be enhanced to address the detection of corrosion under insulation and the materials included in the program in addition to the materials for which the GALL Report recommends for this program. The applicant also stated that the training requirements for inspectors will be enhanced to address the aging effects that are observable on materials included in the program in addition to the materials for which the GALL Report recommends for this program. The staff evaluated the enhancement against the corresponding program element in GALL Report AMP XI.M36. The staff noted that the applicant's program appropriately identified and addressed the additional inspection considerations required for the full set of in
| |
| -scope materials and the concerns for detecting corrosion under insulation. The staff finds the program enhancement acceptable because, when implemented, the program elements will be consistent with the recommendations in GALL Report AMP XI.M36.
| |
| Enhancement 2. By letter dated March 5, 2014, the applicant amended the LRA and provided changes to its response to LR
| |
| -ISG-2012-02, "Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Tanks, and Corrosion under Insulation." For the corrosion under insulation aspect, the applicant provided a new enhancement to include periodic inspections of in-scope insulated components and amended the program description to include the detailed basis for managing loss of material due to corrosion under insulation in insulated plant components. The applicant also included this enhancement as Commitment 78 for UFSAR Table A.3. The staff evaluated the enhancement against the recommendations in LR
| |
| -ISG-2012-02, Appendix F. The staff noted that the amended enhancement for the AMP provided aging management activities and criteria that were consistent with the aging management bases for managing corrosion under insulation in LR
| |
| -ISG-2012-02. Furthermore, the staff finds the program enhancement acceptable because, when implemented, the program will include additional guidance for managing the effects of aging associated with corrosion under insulation, as recommended in LR
| |
| -ISG-2012-02, Appendix F.
| |
| Based on its audit, review of the application, and review of the applicant's responses to RAIs B.2.1.24-1 and RAI B.2.1.24
| |
| -2, the staff finds that elements one through six of the applicant's External Surfaces Monitoring Program, with acceptable exceptions and enhancements, are consistent with the corresponding program elements of GALL Report AMP XI.M36 and, therefore, are acceptable.
| |
| | |
| Aging Management Review Results 3-135 Operating Experience. LRA Section B.2.1.24 summarizes operating experience related to the External Surfaces Monitoring Program. The applicant stated an instance of operating experience in which heat exchanger outlet lines were observed to have corrosion products on the external surface, which was attributed to reaction with condensation. The applicant also stated that an engineering analysis was conducted after the removal of corrosion products, and the analysis indicated that there were no unacceptable levels of corrosion. The staff noted that an alternative anti
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| -sweat insulation was used to replace the original insulation, which permitted the condensate to be retained on the metal surface of the heat exchanger line.
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| In another instance of operating experience, the applicant stated that corrosion was observed on the surface of diesel generator piping. The applicant also stated that ultrasonic measurements were taken of the pipe thickness as part of the engineering analysis conducted to determine the extent of corrosion. Although the pipe wall thickness was recorded to be below the original installation value, an engineering evaluation determined that the applicable design code requirements for all design conditions were satisfied; therefore, the measured reduced wall thickness was deemed acceptable by the applicant.
| |
| The staff reviewed operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program.
| |
| During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking appropriate corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.24, as modified by letter dated March 9, 2015 (ADAMS Accession No. ML14072A018), provides the UFSAR supplement for the External Surfaces Monitoring Program. The staff reviewed this UFSAR supplement description of the program and noted that, although the applicant's basis for managing loss of material due to corrosion under insulation was consistent with that recommended in LR
| |
| -ISG-2012-02, Appendix F, the applicant did not incorporate the details for managing this aging effect and mechanism into the UFSAR supplement summary description for the AMP, as recommended in LR
| |
| -ISG-2012-02, Appendix B. By letter dated November 18, 2014, the staff issued RAI B.2.1.24
| |
| -3, requesting that the applicant provide its justification for why the programmatic bases and criteria for managing loss of material due to corrosion under insulation had not been incorporated into either LRA Section A.2.1.24 or LRA Commitment 78, which was provided in the letter of March 5, 2014.
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| By letter dated March 9, 2015, the applicant responded to RAI B.2.1.24
| |
| -3 by amending LRA Section A.2.1.24 and Commitment 78 to provide additional details relating to activities for Aging Management Review Results 3-136 managing loss of material due to corrosion under insulation in insulated plant components. The staff noted that the amendment of the UFSAR supplement and Commitment 78 provided aging management activities and criteria that were consistent with the aging management bases for managing corrosion under insulation in LR
| |
| -ISG-2012-02. Therefore, the staff finds the amended UFSAR supplement summary description, when coupled with implementation of LRA Commitment 78, is consistent with the criteria in LR
| |
| -ISG-2012-02 for managing loss of material due to corrosion under insulation. RAI B.2.1.24
| |
| -3 is resolved. The staff also noted that the UFSAR supplement description of the program conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Tables 3.2-2, 3.3-2, and 3.4
| |
| -2. The staff also noted that the applicant committed (Commitment Nos. 26 and 78) to enhancing the External Surfaces Monitoring Program prior to entering the period of extended operation. Specifically, the applicant committed to addressing the scope of the program, relevant degradation mechanisms and effects of interest, the RFO inspection frequency, periodic inspections for possible corrosion under insulation on a sample of indoor and outdoor insulated components every 10 years, the training requirements for inspectors, and the required periodic reviews to determine program effectiveness.
| |
| The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's External Surfaces Monitoring Program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exceptions and their justifications and determined that the AMP, with the exceptions, is adequate to manage the aging effects for which the LRA credits it. Also, the staff reviewed the enhancements and confirmed that their implementation through Commitment Nos. 26 and 78 prior to the period of extended operation would make the existing AMP consistent with the GALL Report to which it was compared. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
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| 3.0.3.2.15 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program Summary of Technical Information in the Application. LRA Section B.2.1.25, as amended by letters dated March 5, 2014; March 9, 2015; March 19, 2015; and May 24, 2018, describes the new Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program as consistent, with exceptions and enhancements, with GALL Report AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components." The applicant stated that the program will manage the following aging effects:
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| * cracking due to SCC
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| * loss of material due to general, pitting, crevice, galvanic and microbiologically
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| -influenced corrosion and due to fouling
| |
| * loss of material due to erosion and wear
| |
| | |
| Aging Management Review Results 3-137
| |
| * reduction of heat transfer due to fouling
| |
| * hardening and loss of strength due to elastomer degradation
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| * loss of coating integrity
| |
| * cracking, blistering, and change in color due to water absorption The applicant stated that the program will include opportunistic inspections performed during pre-planned periodic surveillances or during maintenance activities when the systems are opened and the surfaces made accessible for visual inspection. In addition to the opportunistic inspections, the program will also include focused inspections. The applicant also stated that the focused inspections will be performed to ensure that a representative sample of material, environment, and aging effect combinations have been evaluated every 10 years during the period of extended operation. The opportunistic inspections will continue despite meeting the sampling limit. The applicant further stated that the program will manage loss of coating integrity due to blistering, cracking, flaking, peeling, or physical damage of Service Level 3 (augmented) internal coatings for piping, piping fittings, and tanks exposed to raw water.
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| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
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| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.M38. As discussed in the audit report, the staff confirmed that each element of the applicant's program is consistent with the corresponding element of GALL Report AMP XI.M38, with the exception of the "detection of aging effects," "parameters monitored/inspected," and "acceptance criteria" program elements. For these elements, the staff determined the need for additional clarification, which resulted in the issuance of RAIs.
| |
| GALL Report AMP XI.M38 recommends periodic inspections for detection of aging effects prior to the loss of component function. The GALL Report AMP also recommends that locations be chosen to include conditions likely to exhibit the aging effects under the "detection of aging effects" program element description. The applicant's AMP has in
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| -scope components that cannot be reached for hands
| |
| -on inspection and, therefore, are not accessible for the tactile inspection described in the LRA. By letter dated November 18, 2010, the staff issued RAI B.2.1.25-1, requesting that the applicant provide information as to how the tactile techniques would be applied for the in
| |
| -scope components that are inaccessible for physical manipulation.
| |
| In its response dated December 17, 2010, the applicant stated that when an elastomer is inaccessible for tactile inspection, the tactile inspection results of an accessible elastomer of the same construction, in a similar environment, with an equivalent age will be used to assess the condition of the inaccessible elastomer. The applicant also stated that it will apply the same method for determining the condition of metallic components that are inaccessible for visual inspection.
| |
| The staff finds the applicant's response acceptable because visual and tactile inspections are capable of identifying the aging effects managed by the program prior to loss of intended function. Also, inspection of accessible components with similar construction, age, and environment to those of inaccessible components is an acceptable method to project th e condition of components with similar construction, age, and environment that cannot be inspected because they are inaccessible. The staff noted that this is an acceptable method Aging Management Review Results 3-138 used to assess the effects of aging for inaccessible components in other AMPs in the GALL Report. The staff's concern described in RAI B.2.1.25
| |
| -1 is resolved.
| |
| GALL Report AMP XI.M38 recommends that the acceptance criteria be established in the maintenance and surveillance procedures or other established plant procedures under t he "detection of aging effects" program element description. The applicant stated that the results of the program's inspections will be used to establish acceptance criteria for the management of aging effects of in
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| -scope components, but no specific information was provided on how this will be conducted. By letter dated November 18, 2011, the staff issued RAI B.2.1.25
| |
| -2, requesting that the applicant explain how new acceptance criteria will be established instead of having previously
| |
| -established acceptance criteria consistent with the GALL Report recommendations.
| |
| In its response dated December 17, 2010, the applicant revised the LRA to remove the statement that acceptance criteria would be established based on results of the program's inspections. The applicant stated that the acceptance criteria for indications of corrosion or fouling will be identified in the appropriate inspection procedures and will be part of the training and qualification program required for all personnel performing the inspections. The applicant also stated that acceptance criteria will include visual indications of corrosion, corrosion byproducts, coating degradation, surface discoloration, scale, deposits, pits, and surface discontinuities. The applicant further stated that personnel performing the inspections will be trained to identify when the as
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| -found condition of the component requires further evaluation using the site corrective action program.
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| The staff finds the applicant's response acceptable because the applicant will establish acceptance criteria in the inspection procedures, and the personnel performing the inspections will be trained and qualified to identify when the acceptance criteria have not been met and the component condition requires additional evaluation. The staff's concern described in RAI B.2.1.25-2 is resolved.
| |
| GALL Report AMP XI.M38 recommends that the visible evidence of corrosion may indicate possible loss of materials. The applicant stated that a thin, light, even layer of oxidation provides protection against further corrosion. The staff has concluded that this is not accurate for most of the in
| |
| -scope materials and, when taken in general context, is not accurate. By letter dated November 18, 2011, the staff issued RAI B.2.1.25
| |
| -3, requesting that the applicant provide technical clarification on the specific in
| |
| -scope materials to which the subject statement is intended to describe. The applicant was also asked to explain how this statement pertains to monitoring of oxidation by the inspectors in this program.
| |
| In its response dated December 17, 2010, the applicant stated that the program will be modified to remove the statement that a thin, light, even layer of oxidation provides protection against further corrosion. The intent of this sentence was not to provide an inspection criterion but to convey that corrosion occurs differently for different materials and in a range of environments. The staff finds the applicant's response acceptable because the applicant corrected a statement in the AMP that, although accurate for some in
| |
| -scope materials, is not accurate for all of the materials in
| |
| -scope for the AMP. The staff's concern described in RAI B.2.1.25
| |
| -3 is resolved.
| |
| Subsequent to the submittal of the LRA, the staff issued LR
| |
| -ISG-2012-02, "Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation," which revised several GALL Report AMPs including the guidance for AMP XI. M38. The guidance in GALL Report AMP XI.M38 was revised to recommend that 20 percent or a Aging Management Review Results 3-139 maximum of 25 components for each material, environment and aging effect (MEA) combination be inspected each 10
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| -year period during the period of extended operation.
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| By letter dated March 5, 2014, the applicant submitted an LRA supplement in response to LR-ISG-2012-02. The LRA supplement included revisions to the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program and associated UFSAR section. The UFSAR supplement states that a "representative" sample will be inspected and the AMP states that "approximately" 20 percent of each MEA combination will be inspected. By letter dated November 18, 2014, the staff issued RAI B.2.1.25
| |
| -4, requesting that the applicant clarify the minimum sample size to be inspected by the program. Specifically, to describe what "approximately" 20 percent relates to numerically, as used in LRA Section B.2.1.25, and "representative" sample relates to numerically, as used in LRA Section A2.1.25 to describe the population being inspected.
| |
| In its response dated March 9, 2015, the applicant revised its AMP to state that a representative sample of 20 percent of each applicable MEA combination will be inspected. The applicant also revised the UFSAR supplement to clarify that a representative sample consists of 20 percent or a maximum of 25 components for each applicable MEA combination.
| |
| The staff finds the applicant's response acceptable because the AMP was revised to state that the minimum sample size to be inspected is 20 percent for each MEA combination and the UFSAR supplement was revised to clarify the sampling population. The minimum sample size and sampling population are consistent with GALL Report AMP XI.M38, as modified by LR
| |
| -ISG-2012-02. The staff also reviewed the portions of the "scope of program," and "parameters monitored or inspected" program elements associated with exceptions to determine if the program will be adequate to manage the aging effects for which it is credited. The staff's evaluation of these exceptions follows.
| |
| Exception 1. LRA Section B.2.1.25 states an exception to the "scope of program" program element. The applicant's AMP includes components made from additional materials such as aluminum, CASS, copper alloy, copper alloy greater than 15 percent zinc, elastomer, galvanized steel, gray cast iron, nickel alloy, and stainless steel, whereas the GALL Report recommends the program for steel components.
| |
| The staff reviewed this exception to the GALL Report and noted that the applicant took the exception because additional materials are to be covered in the applicant's AMP that are not covered by other AMPs. The staff evaluated the exception and determined that the exception is adequate because the inspection methods included in the program are standard methods that are adequate for the detection of age
| |
| -related degradation that may occur in the materials covered by the applicant's AMP.
| |
| Exception 2. LRA Section B.2.1.25 states an exception to the "parameters monitored or inspected" program element. The applicant stated that the program will include inspections for the aging effects of cracking, reduction of heat transfer, and hardening and loss of strength. The staff reviewed this exception to the GALL Report and noted that the applicant took the exception because additional aging effects are covered in the applicant's AMP that are beyond those recommended by the GALL Report. The staff evaluated the exception and determined Aging Management Review Results 3-140 that the exception is adequate because the additional aging effects being managed by the program are addressed with corresponding standard inspection methods. Specifically, the use of tactile inspection methods and their correlation to inaccessible components will be used to address the additional aging effects being managed for the in
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| -scope elastomers.
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| Enhancement 1
| |
| . LRA Section B.2.1.25, as amended by letter dated March 5, 2014, states an enhancement to "include performance of focused examinations to provide a representative sample of 20 percent, or a maximum of 25, of each identified material, environment, and aging effect combination in each 10
| |
| -year period during the period of extended operation." The applicant stated that, when practical, the focused inspections will be performed on components most susceptible to aging. The staff evaluated the enhancement and determined that it is consistent with the guidance in LR
| |
| -ISG-2012-02 and will ensure that a representative minimum sample size is inspected during each 10
| |
| -year period of extended operation.
| |
| Enhancement 2. LRA Section B.2.1.25, as amended by letter dated March 5, 2014, states that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program will be augmented to include the requirements associated with managing loss of coating integrity that are addressed, as well as the staff's evaluation of the changes, in SER Section 3.0.3.4. Enhancement 3. LRA Section B.2.1.25, as amended by letter dated May 19, 2015, states that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program will be enhanced to include Service Level 3 coating requirements in the RCP motor refurbishment procedure and all four RCP motors will be refurbished using these requirements prior to entering the period of extended operation. The staff's evaluation of this enhancement is documented in SER Section 3.0.3.4.
| |
| Based on its audit, review of the application, and review of the applicant's responses to RAIs B.2.1.25-1, B.2.1.25
| |
| -2, B.2.1.25
| |
| -3, and RAI B.2.1.25
| |
| -4, the staff finds that elements one through six of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, with acceptable exceptions and enhancements, are consistent with the corresponding program elements of GALL Report AMP XI.M38 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.25 summarizes operating experience related to the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The applicant described one instance of operating experience in which corrosion was detected inside the shell of a storage tank heat exchanger. The applicant stated that the observation was followed by an engineering assessment during which it was determined that the corrosion was not significant and no further action was indicated at the time. The applicant further stated that, during a followup inspection, an ultrasonic examination was performed, and parts of the heat exchanger were measured to be below the minimum wall thickness requirement. A base metal repair was performed prior to returning the heat exchanger to service.
| |
| In another instance of operating experience, the applicant described a case in which corrosion was found on an internal part of a screen wash system valve during a maintenance activity. The applicant stated that the valve was replaced and, based on the knowledge of this instance of observed degradation, an extent of condition evaluation was performed on valves in similar service environments that could potentially be subjected to the same corrosion effect. The Aging Management Review Results 3-141 applicant stated that preventive maintenance activities were developed for the disassembly and inspection of all similar valves with a frequency of every 6 years.
| |
| The staff reviewed operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program. During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking appropriate corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.25, as amended by letters dated March 5, 2014; March 9, 2015; May 24, 2018; and June 20, 2018, provides the UFSAR supplement for the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in Table 3.0
| |
| -1 of LR-ISG-2012-02. The staff also noted that the applicant committed (Commitment 27) to implementing the new Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program prior to entering the period of extended. The applicant also committed (Commitment 73) to performing focused examinations as part of the Inspection of Interna l Surfaces in Miscellaneous Piping and Ducting Components Program. The applicant further committed (Commitment Nos. 82 and 89) to enhancing the program to address loss of coating integrity. The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its audit and review of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exceptions and their justifications and determined that the AMP, with the exceptions, is adequate to manage the aging effects for which the LRA credits it. Also, the staff reviewed the enhancements and confirmed that their implementation prior to the period of extended operation will make the AMP adequate to manage the applicable aging effects. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.2.16 Lubricating Oil Analysis Program Summary of Technical Information in the Application. LRA Section B.2.1.26 describes the existing Lubricating Oil Analysis Program as consistent, with an exception and enhancements, Aging Management Review Results 3-142 with GALL Report AMP XI.M39, "Lubricating Oil Analysis." The applicant stated that the Lubricating Oil Analysis Program is an existing program that performs oil condition monitoring activities to manage the aging effects of loss of material due to galvanic, general, pitting, crevice, microbiologically
| |
| -influenced corrosion, fouling, and heat transfer degradation due to fouling. The applicant further stated that the purpose of the Lubricating Oil Analysis Program is to obtain and analyze lubricating oil samples from plant equipment to ensure that the oil quality is maintained within established limits. The applicant also stated that the program includes sampling and analysis of lubricating oil for components within the scope of license renewal and subject to an AMR.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff also reviewed the portions of the "parameters monitored or inspected" and "detection of aging effects" program elements associated with an exception and enhancements to determine if the program will be adequate to manage the aging effects for which it is credited. The staff's evaluation of these exception and enhancements follows.
| |
| Exception 1. LRA Section B.2.1.26 states an exception to the "parameters monitored or inspected" program element. The GALL Report recommends that for components that do not have regular oil changes, tests for viscosity, neutralization number, and flash point may be used to determine lubricating oil suitability for continued use. Alternatively, this program element in the LRA states that Seabrook does not sample for flash point in lubricating oil samples. Instead, the applicant stated that when there is a potential for lubricating oil contamination by fuel, Seabrook will test the samples for fuel dilution. The applicant further stated that testing for fuel dilution is equivalent to testing for flash point because either test will provide an indication of fuel in-leakage. The staff reviewed this exception to the GALL Report and noted that the applicant takes exception to the GALL Report in that Seabrook does not sample for flash point in lubricating oil samples. The staff determined that more information was needed. By letter dated December 14, 2010, the staff asked the applicant to discuss the method Seabrook uses to determine fuel dilution and explain how it compares to sampling for flash point.
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| In its response by letter dated January 13, 2011, the applicant stated that Seabrook will add flash point testing as a requirement for in
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| -scope diesel engine lube oil analysis. The applicant indicated that ASTM Standard D 6224-98, "Standard Practice for In
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| -Service Monitoring of Lubricating Oil for Auxiliary Power Plant Equipment," recommends flash point testing to diesel engine oils. As such, the applicant stated that flash point is of little significance for determining the degree of degradation of used oil since normal degradation has little effect on the flash point. The applicant stated that Seabrook will limit the flash point testing to those lube oil samples that have the potential for contamination by fuel. The applicant stated that potential for fuel contamination is limited to the two main emergency diesel generators and the two diesel fire pumps. The staff finds this exception acceptable and consistent with the one described in the GALL Report Section XI.M39 because the program will be enhanced to include flash point testing for Aging Management Review Results 3-143 lube oil samples that have the potential for fuel contamination, the potential for which is limited to the two main emergency diesel generators and the two diesel fire pumps. Flash point testing is an acceptable method used to determine fuel contamination in lubricating oil for components that do not have regular oil changes such as the two main emergency diesel generators and the two diesel fire pumps.
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| On the basis of its review, that staff finds this program exception acceptable because this program will be enhanced to include flash point testing, which is recommended by the GALL Report AMP XI.M39.
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| Enhancement 1. LRA Section B.2.1.26 states an enhancement to the "parameters monitored or inspected" program element. This enhancement expands on the existing program element by adding an attachment list that specifies the required equipment for the program, sampling frequency, discussion on the required periodic oil changes, and includes the associated lube oil analysis required. In a letter dated January 13, 2011, in response to RAIs by letter dated December 14, 2010, the applicant modified this enhancement to include flash point testing for lubricating oil that has the potential for contamination by fuel.
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| On the basis of its review, the staff finds this enhancement acceptable because, when it is implemented, prior to the period of extended operation, it will make the program consistent with the recommendations of GALL Report AMP XI.M39.
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| Enhancement 2. LRA Section B.2.1.26 states an enhancement to the "detection of aging effects" program element. This enhancement expands on the existing program element by adding a requirement to sample the oil for the reactor coolant pump (RCP) oil collection tanks.
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| On the basis of its review, the staff finds this enhancement acceptable because periodic sampling and compliance with acceptance criteria ensures lube oil contaminants do not exceed acceptable levels, thereby preserving the environment that could lead to the aging effects of loss of material. Also, when it is implemented, prior to the period of extended operation, it will make the program consistent with the recommendations of GALL Report AMP XI.M39.
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| Enhancement 3. LRA Section B.2.1.26 states an enhancement to the "detection of aging effects" program element. This enhancement expands on the existing program element by adding a requirement to perform a one
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| -time ultrasonic thickness measurement of the lower portion of the RCP oil collection tanks prior to the period of extended operation.
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| On the basis of its review, the staff finds this enhancement acceptable because compliance with acceptance criteria ensures lube oil contaminants do not exceed acceptable levels, thereby preserving the environment that could lead to the aging effects of loss of material. Also, when it is implemented, prior to the period of extended operation, it will make the program consistent with the recommendations of GALL Report AMP XI.M39.
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| Based on its audit and review of the application, the staff finds that program elements one through six of the applicant's Lubricating Oil Analysis Program, with acceptable exception and enhancements, are consistent with the corresponding program elements of GALL Report AMP XI.M39 and, therefore, are acceptable.
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| Operating Experience. LRA Section B.2.1.26 summarizes operating experience related to the Lubricating Oil Analysis Program. The staff reviewed this information and interviewed the Aging Management Review Results 3-144 applicant's technical personnel to confirm that the applicable aging effects and industry
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| - and plant-specific operating experience have been reviewed by the applicant and are evaluated in the GALL Report. During the audit, the staff independently confirmed that the applicant adequately incorporated and evaluated operating experience related to this program.
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| The staff reviewed the operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
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| -specific operating experience were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program.
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| During its review, the staff found no operating experience to indicate that the applicant's program would be ineffective in adequately managing aging effects during the period of extended operation.
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| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the application taking appropriate corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
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| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
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| UFSAR Supplement. LRA Section A.2.1.26 provides the UFSAR supplement for the Lubricating Oil Analysis Program. The staff reviewed the UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP
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| -LR Tables 3.2
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| -2, 3.3-2, and 3.4
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| -2. The staff also noted that the applicant committed (Commitment Nos. 28, 29, and 30) to enhance the Lubricating Oil Analysis Program prior to entering the period of extended operation.
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| Specifically, the applicant committed to do the following:
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| (1) Enhance the program to add required equipment, required lube oil analysis required, sampling frequency, and periodic oil changes. In addition, the program will be required to include flash point testing when there is a potential for contamination of the lubricating oil by fuel.
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| (2) Enhance the program to sample the oil for the RCP oil collection tanks.
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| (3) Enhance the program to require the performance of a one
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| -time ultrasonic thickness measurement of the lower portion of the RCP oil collection tanks prior to the period of extended operation.
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| The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
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| Conclusion. On the basis of its audit and review of the applicant's Lubricating Oil Analysis Program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and its justification and determined that the AMP, with the exception, is adequate to manage the Aging Management Review Results 3-145 aging effects for which the LRA credits it. Also, the staff reviewed the enhancements and confirmed that their implementation through Commitment Nos. 28, 29, and 30 prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it was compared. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
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| 3.0.3.2.17 ASME Code Section XI, Subsection IWL Aging Management Program Summary of Technical Information in the Application. LRA Section B.2.1.28, as revised through various LRA supplements and the applicant's letters described below, discusses the existing ASME Section XI, Subsection IWL AMP as consistent, with enhancements, with GALL Report, Revision 1, AMP XI.S2, "ASME Section XI, Subsection IWL." The LRA states that all accessible reinforced concrete containment components are within the scope of this program. The LRA also states that the program complies with the examination requirements and acceptance criteria of ASME B&PV Code, Section XI, Subsection IWL, "Requirements for Class CC Concrete Components of Light
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| -Water Cooled Power Plants," 1995 Edition with 1996 Addenda, as incorporated by reference in 10 CFR 50.55a. The LRA further states that this program manages the effects of aging for "loss of bond, loss of material (spalling, scaling) due to corrosion of embedded steel, expansion and cracking due to reaction with aggregates, increase in porosity and permeability, cracking, loss of material (spalling, scaling) due to aggressive chemical attack, and increase in porosity and permeability, loss of strength due to leaching of calcium hydroxide" on the reinforced concrete containment building.
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| The LRA states that testing and evaluation of concrete degradation due to aggressive chemical attack will be performed and corrective actions will be taken. In addition, the LRA states that the applicant will evaluate the acceptability of concrete in inaccessible areas of the containment consistent with the regulatory requirements of 10 CFR 50.55a(b)(2)(viii), when conditions exist in accessible areas that could indicate the presence of or result in degradation to such inaccessible areas.
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| Updates to the program description By letters dated December 10, 2010, May 15, 2014, and February 28, 2018 (ADAMS Accession Nos. ML103540534, ML14142A220, and ML18075A391) the applicant revised LRA Section B.2.1.28 program description incorporating program changes to include information on:
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| * Integration of ACI
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| -349.3R acceptance criteria for degraded concrete evaluation
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| * Definition of degradation due to ASR on concrete surface areas as:
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| Acceptable (i.e., No ASR; defines Tier 1, as described in the letter dated May 15, 2014);
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| Acceptable with deficiencies and for further review (Combined Cracking Index (CCI)) of less than 1.0 mm/m or Individual Crack Width of less than 1.0 mm; defines Tier 2);
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| Aging Management Review Results 3-146 Unacceptable requiring further evaluation (CCI of 1.0 mm/m or greater, or an Individual Crack Width of 1.0 mm or greater; defines Tier 3);
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| * Procedures for performing the VT1
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| -C and VT3-C as general and detailed visual examinations of the concrete surfaces of the primary containment in accordance with requirements of ASME Code Section XI, Subsection IWL, 2004 Edition and no Addenda (in effect since August 19, 2010);
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| * Procedures to identify areas and types of concrete deterioration and distress, as described in ACI 201.1 and ACI 349.3R; and
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| * Integration of the ASME Code Section XI, Subsection IWL Program with the Structures Monitoring Program to monitor, trend, and evaluate observed indications of ASR; and compare results of new examinations against baseline examinations and prior inservice (ISI) results.
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| Summary of Staff Evaluation. The staff reviewed the program elements of the ASME Section XI, Subsection IWL AMP and found them consistent with the corresponding program elements of GALL Report AMP XI.S2. However, based on the cracking due to expansion from reaction with aggregates, or ASR, degradation mechanism affecting concrete at Seabrook, the applicant enhanced the ASME Code Section XI, Subsection IWL AMP to demonstrate that the effects of ASR will be managed and that there is reasonable assurance that the concrete containment structure will adequately perform its intended function during the period of extended operation. The applicant also enhanced the "preventive actions," "monitoring and trending," and "acceptance criteria" program elements. In lieu of enhancing the "parameters monitored or inspected" and "detection of aging effects" program elements of the ASME Section XI, Subsection IWL AMP the applicant augmented this AMP by creating a new plant
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| -specific "Alkali Silica Reaction Monitoring" AMP. In addition, the applicant also integrated portions of the Structures Monitoring AMP and the new plant
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| -specific Building Deformation Monitoring AMP with the ASME Section XI, Subsection IWL AMP. The staff's evaluation of the ASR-related AMPs are in Sections 3.0.3.3.6 and 3.0.3.3.7, respectively.
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| The Seabrook containment is a concrete cylinder topped with a hemispherical dome, supported on a reinforced concrete foundation mat. The containment is encapsulated within the containment enclosure building, which is also a concrete cylinder with a hemispherical dome. There is an annular space of five feet between the containment and the containment enclosure building. The below grade portion of the containment is not in contact with the soil or ground water. However, for some time in the past, the bottom six feet of the concrete containment was in contact with groundwater that leaked through the containment enclosure building and filled the annular space. The groundwater from this area has since been removed, and the applicant has committed to keep this annular space dry in the future. Isolated areas of the concrete containment that were previously exposed to the groundwater have indications of cracking.
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| The staff's June 8, 2012, SER with Open Items (OIs) discusses the staff's concerns regarding whether the applicant would: (1) take adequate measures to preserve the integrity of the concrete containment structure through testing and evaluation of its cracked area to determine if the cracks are due to ASR (OI 3.0.3.2.18
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| -1); and (2) dewater the annular space between the containment and containment enclosure buildings (OI 3.0.3.1.9
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| -1). The staff concerns identified in OI 3.0.3.1.9
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| -1 are briefly discussed below in the staff evaluation of Enhancement 2, and full y discussed and resolved in SER Section 3.0.3.1.9. The staff's concerns associated with OI 3.0.3.2.18
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| -1 have also been briefly discussed in the Staff Evaluation of
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| | |
| Aging Management Review Results 3-147 Enhancement 2 (Deleted) and in the Operating Experience section below. The staff's comprehensive discussion and resolution of OI 3.0.3.2.18
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| -1 is documented in SER Section 3.0.3.2.18.
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| Staff Evaluation. This section of the SER addresses the staff's review and evaluation of the applicant's ASME Section XI, Subsection IWL AMP for the Seabrook concrete containment structure only. However, this AMP also references the LRA Section B.2.1.31, "Structures Monitoring"; LRA Section B.2.1.31A, "Alkali Silica Reaction Monitoring"; and LRA Section B.2.1.31B, "Building Deformation Monitoring" AMPs, reviewed and evaluated in SER Sections 3.0.3.2.18, 3.0.3.3.6, and 3.0.3.3.7, respectively.
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| During its LRA audit, the staff reviewed the applicant's claim of consistency of its ASME Section XI, Subsection IWL AMP with that of the GALL Report AMP XI.S2. The staff compared program elements one through six of the applicant's program with the corresponding program elements of GALL Report AMP XI.S2. As discussed in the LRA audit report dated March 21, 2011 (ADAMS Accession No. ML110280424), the staff confirmed that each program element of the applicant's AMP is consistent with the corresponding program element of GALL Report AMP XI.S2, with the exception of the "acceptance criteria" program element. For this program element, the staff determined the need for additional information, which resulted in the issuance of RAIs discussed below.
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| The "acceptance criteria" program element in GALL Report AMP XI.S2 recommends that acceptance standards for evaluation of concrete containments follow IWL
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| -3000 of the ASME Code Section XI. Acceptance of concrete surfaces rely on the "responsible engineer," who in accordance with IWL
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| -2320 and IWL
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| -2310 is a registered professional engineer who performs general visual examinations in sufficient detail to identify concrete "deterioration and distress, such as defined in ACI 201.1." The GALL Report AMP XI.S2 provides added guidance to these ASME Code Section XI requirements augmenting the qualitative assessment of ACI 201.1 with the quantitative acceptance criteria of ACI 349.3R, Chapter 5. During its audit, the staff was not clear how the degradation of the concrete containment had been quantified, tracked, and trended for use as a baseline for the period of extended operation. The staff reviewed the preventive maintenance work orders used for tracking and identifying conditions (a sample of which are discussed in the audit report), and the site procedure that describes acceptance criteria for concrete containment surface evaluations. The staff noted that the applicant does not implement the three
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| -tier evaluation criteria of Chapter 5 of ACI 349.3R. The staff also noted that visual inspections of the concrete containment indicated areas of spalled concrete that equaled or exceeded a depth of 1 in. In accordance with in ACI 349.3R
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| -02, Section 5.1, spalled areas that exceed a depth of 3/8 in., and 4 in. in any dimension, must be evaluated.
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| By letter dated November 18, 2010 (ADAMS Accession No. ML103090558), the staff issued RAI B.2.1.28
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| -1 requesting that the applicant provide details on: (1) methods used to identify containment concrete surface conditions and how these conditions are tracked, trended, and evaluated; and (2) the frequency of examinations and whether acceptance criteria followed, and actions taken, are in conformance with ASME Code Section XI, Subsection IWL, and NRC IN 2010-14, "Containment Concrete Surface Condition Examination Frequency and Acceptance Criteria."
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| In its response dated December 17, 2010 (ADAMS Accession No. ML103540534), the applicant stated that:
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| Aging Management Review Results 3-148 Any Containment concrete degradation identified during IWL Examinations is documented (per the implementing procedure) on Examination Forms, using the guidance of ACI 349.3R and ACI 201.1R for condition quantification, description and terminology. The degraded area is marked in the field with an identifying label to guide the Responsible Engineer's review, and subsequent Examination review. An Action Request (AR) is generated for Examination Forms that document degradation, requiring an Evaluation by the Responsible Engineer. The Forms and Evaluations are retained and reviewed prior to the next Examination. During the subsequent Examination, previously reported areas are re-examined to determine if there has been any change in their condition.
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| The retained Forms and Evaluations from each successive Examination will be maintained up to and through the Period of Extended Operation, thereby creating a continuous record of the condition of the Containment concrete.
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| With regards to IN 2010-14, the applicant stated that the "Seabrook Inservice Inspection Procedure Primary Containment Section XI IWL Program" was revised in October 2010 to "include the guidance of ACI 201.1R and ACI 349.3R for identifying degradation during g]eneral
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| [v]isual [e]xaminations." The staff finds that the revision made to the "Seabrook Inservice Inspection Procedure Primary Containment Section XI IWL Program," to include the quantitative guidance of ACI 349.3R is acceptable because the implemented acceptance criteria of Chapter 5 of ACI 349.3R make the AMP consistent with GALL Report AMP XI.S2. The staff's concern described in RAI B.2.1.28
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| -1 is resolved.
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| The staff also was not clear how areas of spalling are evaluated. Therefore, by letter dated November 18, 2010, the staff issued RAI B.2.1.28
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| -2 requesting that the applicant describe methods used to evaluate spalled areas that exceed: (1) a depth of 3/8 in., and 4 in. in any dimension, for "Acceptance After Review"; and (2) a depth of 3/4 in., and 8 in. in any dimension, for "Conditions Requiring Further Evaluation" criteria delineated in Chapter 5 of ACI 349.3R
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| -02. In addition, the staff requested the applicant to provide findings from the most recent engineering evaluation report prepared in compliance with ASME Section XI, IWL requirements.
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| The applicant responded to RAI B.2.1.28
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| -2 in a letter dated December 17, 2010, and stated that prior to August 18, 2010, Seabrook conducted the IWL examinations in accordance with ASME Code Section XI, Subsection IWL, 1995 Edition with 1996 Addenda with deficiencies reported in qualitative terms and evaluations performed by the responsible engineer, a licensed professional engineer, using the methodology described in the RAI B.2.1.28
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| -1 response. The staff also noted that since September 2010, IWL examinations were performed in accordance with ASME Code Section XI, 2004 Edition and no Addenda, and the recommended guidance of ACI 201.1R and ACI 349.3R. The staff further noted that the Responsible Engineer performed evaluations and quantified identified deficiencies per ACI 349.3R. In its response, the applicant also provided the following summary of findings from the September 2010 IWL examination:
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| Five Action Requests (ARs) were issued during the ASME Code Section XI, IWL examinations of the Containment concrete; eighty
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| -four (84) deficient areas were identified that required an Engineering Evaluation.
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| Each of the reported discontinuities in the Containment concrete were individually reviewed and evaluated by Design Engineering. All of the reported Aging Management Review Results 3-149 discontinuities were accepted as
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| -is with no further technical evaluation or remediation, based on the criteria of ACI 349.3R.
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| The staff finds the use of acceptance criteria in ACI 349.3R to evaluate concrete containment deficiencies and discontinuities acceptable, because it makes the applicant's AMP consistent with GALL Report AMP XI.S2. The staff's concern described in RAI B.2.1.28
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| -2 is resolved.
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| The staff also reviewed the portions of the "acceptance criteria," "preventive actions," and "parameters monitored or inspected" program elements associated with enhancements to determine if the program will be adequate to manage the effects of aging for which it is credited. The staff's evaluation of these enhancements follows. Enhancement 1. LRA Section B.2.1.28 includes an enhancement to the "acceptance criteria" program element. The applicant stated that the enhancement involves the definition of "Responsible Engineer" (i.e., Registered Professional Engineer) to be included in the applicant's procedure for implementing its ASME Section XI, Subsection IWL AMP, as outlined in Commitment 31.
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| The staff reviewed this program element enhancement against the corresponding program element in GALL Report AMP XI.S2 and finds it acceptable, because when it is implemented it will require the responsible engineer to be a "Registered Professional Engineer" in accordance with IWL-2310 and this is consistent with the "acceptance criteria" program element of GALL Report AMP XI.S2. Enhancement 2 (Deleted). By letter dated December 17, 2010, in response to RAI B.2.1.28
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| -3, evaluated and dispositioned by the staff in the Operating Experience section below, the applicant revised LRA Section B.2.1.28 to include an enhancement to the "parameters monitored or inspected" program element. The applicant stated that through this enhancement it would perform confirmatory testing and evaluation to determine the concrete compressive strength, the presence or absence of ASR, the concrete modulus of elasticity, and the presence or absence of rebar degradation of the containment structure concrete prior to the period of extended operation. However, by letter dated August 11, 2011 (ADAMS Accession No. ML11227A023), in its response to RAI Follow
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| -up B.2.1.28
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| -3, evaluated and dispositioned by the staff in the Operating Experience section below, the applicant deleted this enhancement and the associated (at the time) Commitment 51 from the LRA, with the justification that:
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| Program enhancement and commitment to confirmatory testing cannot be made until aging effects due to ASR are fully understood - [and a] planned approach to addressing ASR degradation throughout the site [would] be included in an engineering evaluation scheduled to [be] complete[d] in March of 2012 - [with] [p]lans to monitor the extent of cracking and expansion in concrete -.
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| By letter dated May 16, 2012 (ADAMS Accession No. ML12142A323), the applicant supplemented the LRA with a new plant
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| -specific AMP, augmenting LRA Section B.2.1.31, "Structures Monitoring," and documented as LRA Section B.2.1.31A, "Alkali
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| -Silica Reaction [ASR] Monitoring," to manage the effects of aging due to ASR (i.e., cracking due to expansion and reaction of cement with aggregates) in concrete structures.
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| The staff reviewed the applicant's deletion of Enhancement No. 2 and Commitment 51 and determined that it needed additional information for the proposed plant
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| -specific ASR Monitoring Aging Management Review Results 3-150 AMP. The final revision of the ASR Monitoring AMP and associated RAIs for that AMP are reviewed and evaluated by the staff in SER Section 3.0.3.3.6. The staff finds that the deletion of this enhancement and corresponding Commitment 51 is acceptable because the applicant has created a new plant
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| -specific ASR Monitoring AMP that the staff finds acceptable for monitoring the extent of cracking and expansion of aggregates in concrete due to ASR.
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| This issue, previously identified in the SER with Open Items as OI 3.0.3.2.18
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| -1, based on the above, is resolved and closed. Additional basis for staff closure of this open item is discussed in the Operating Experience section below.
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| Enhancement 2 (identified as Enhancement 2 in LRA Supplement 60, dated February 28, 2018, but identified as Enhancement 3 in LRA letter dated December 17, 2010, and SER with Open Items). By letter dated December 17, 2010, the applicant revised LRA Section B.2.1.28 to include an enhancement to the "preventive actions" program element. This enhancement involves implementing measures to maintain the exterior surface of the containment structure from elevation
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| -30 ft. to +20 ft. in a dewatered state. In addition, the applicant committed (Commitment 52) to implement these measures prior to the period of extended operation. Specifics on the origin of this enhancement are discussed in the Operating Experience section below. Subsequently, by letters dated April 14, 2011; April 22, 2011; and September 13, 2013 (ADAMS Accession Nos. ML11108A131, ML11115A116, and ML13261A145, respectively), the applicant revised the implementation date of Commitment 52, and in Supplement 60, dated February 28, 2018, it stated that the commitment was completed.
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| The staff reviewed this enhancement against the corresponding program element in GALL Report AMP XI.S2. The staff noted that no preventive actions are specified in GALL Report AMP XI.S2 for concrete degradation. However, maintaining the exterior surface of the containment structure from elevation
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| -30 ft. to +20 ft. in a dewatered state is an appropriate preventive action because it will ensure that the exterior surface of the concrete containment will not be exposed to water that could contribute to cracking due to expansion from reaction with aggregates. The staff also noted that during September 2011, NRC inspectors examined the subject area and found the exterior surface of the containment to be in a dewatered state with sump pumps used to dewater the area. Therefore, the staff finds this enhancement and Commitment 52 to be acceptable, because it has been completed and it eliminates the continual exposure of concrete containment and the concrete containment enclosure building to groundwater, thus mitigating further degradation of concrete due to ASR.
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| The staff also finds OI 3.0.3.1.9
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| -1 closed because the applicant completed the Commitment action to maintain the annulus region between the containment and the containment enclosure building in a dewatered state thus mitigating potential additional aging effects of aggregate expansion due to ASR, as noted in the Enhancement 2 (Deleted) above. OI 3.0.3.1.9
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| -1 is resolved and the staff's closure of the open item is documented in SER Section 3.0.3.1.9, "ASME Section XI, Subsection IWE."
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| Enhancement 3. By letter dated February 28, 2018, the applicant revised LRA Section B.2.1.28 to include an enhancement to the "monitoring and trending" program element and a corresponding commitment (Commitment 55) to be fulfilled by September 1, 2020. The LRA states that implementation of this enhancement ensures that concrete containment suspect distress areas from the 2010 and 2016 ASME Section XI, Subsection IWL, inspections are incorporated appropriately into the next revision of the Seabrook Station Containment lnservice Aging Management Review Results 3-151 Inspection (CISI) Plan. This enhancement was provided in response to RAI B.2.1.28
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| -5, which is evaluated and dispositioned by the staff in the Operating Experience section below.
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| The staff reviewed this enhancement and Commitment 55 and finds the applicant's approach to register the visually identified suspect concrete surface areas from the 2010 and 2016 ASME Section XI, Subsection IWL, inspections into the next revision of its CISI Plan acceptable, because: (1) these areas have been selected through general and detailed visual examinations in accordance with the tiered acceptance criteria of ACI 349.3R, further amplified by monitoring CCI and/or measurement of distinct individual crack widths to assess ASR progression; and (2) examinations are in accordance with L1.11, "Concrete Surface
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| -All Accessible Surface Areas," and L1.12, "Concrete Surface Suspect," of Table IWL 2500
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| -1 of ASME Code Section XI requirements, that also satisfy the "monitoring and trending" program element criteria of GALL Report AMP XI.S2. The staff also finds completion of Commitment 55 by September 1, 2020, acceptable because the next revision of the applicant's CISI Plan would be in accordance with the regulatory requirements of 10 CFR 50.55a, incorporating the latest Edition of ASME Code Section XI (currently 2013 Edition with noted exceptions) 12 months prior to the start of the 120
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| -month inspection interval scheduled to begin August 19, 2020.
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| Based on its audit, review of the application, and review of the applicant's responses to RAI B.2.1.28-1 and RAI B.2.1.28
| |
| -2, the staff finds that program elements one through six for which the applicant claimed consistency with the GALL Report are consistent with the corresponding program elements of the GALL Report AMP XI.S2. In addition, the staff reviewed the enhancements associated with the "acceptance criteria," "preventive actions," and "monitoring and trending" program elements, along with the steps taken for replacing Enhancement 2 (Deleted) referencing the "parameters monitored and inspected" program element with a new plant
| |
| -specific ASR Monitoring AMP, and finds that when these are implemented they will make the AMP adequate to manage the applicable aging effects.
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| Operating Experience. LRA Section B.2.1.28 summarizes operating experience related to the ASME Section XI, Subsection IWL AMP. The applicant stated that this program is implemented through the "Seabrook Station Containment Surface Inspection Program," and that the containment structure concrete has been found to be in good condition during inspections performed in accordance with ASME Code Section XI, Subsection IWL. The applicant further stated that containment inspections performed in 2002, 2005, and 2008 "were completed satisfactorily with no indication of degradation of the concrete surfaces."
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| The staff reviewed operating experience information in the application and during the audit to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant had adequately evaluated and incorporated operating experience related to this program.
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| During its review, the staff identified operating experience indicating that the applicant's ASME Section XI, Subsection IWL Program may not be effective to adequately manage the aging effect of cracking due to expansion from reaction with aggregates (i.e., ASR) during the period of extended operation. The staff determined the need for additional clarifications, which resulted in the issuance of RAIs.
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| In LRA Section B.2.1.28, the applicant stated that concrete degradation due to aggressive chemical attack is an aging effect applicable to Seabrook, and that the Structures Monitoring Aging Management Review Results 3-152 Program addresses the plan and specific details to determine the effects of aggressive chemical attack on the concrete. The applicant further stated that an evaluation would be conducted after the testing in the plan is performed, and, if required, actions would be provided using the corrective action process for concrete under the Structures Monitoring Program and the ASME Code Section XI, Subsection IWL AMP.
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| During the audit the staff found that initial testing results for concrete samples obtained from below-grade areas of other safety
| |
| -related structures indicate that the concrete in these areas is exhibiting cracking due to ASR. The staff also found that groundwater migrated into the annular space between the concrete enclosure building and concrete containment, and the bottom 6 ft. of the concrete containment wall was in contact with the groundwater for an extended period of time. Furthermore, cracks due to ASR have been observed in different Seabrook plant concrete structures, including the concrete containment enclosure building. Although water is a contributing factor to cement
| |
| -aggregate reactions as discussed in ACI 349.3R
| |
| -02, Section 4.2.5, the applicant stated that the containment concrete in the annulus does not exhibit evidence of cracking due to expansion and reaction with aggregates. A review of Seabrook condition reports by the staff (a sample of which are documented in the audit report) did not identify inspection findings that discussed cracking of concrete due to expansion and reaction with aggregates or nondestructive or destructive test data that quantify the magnitude or extent of cracking of accessible above
| |
| -grade and below
| |
| -grade portions of the concrete containment.
| |
| The staff noted that ASR might be occurring in the containment, particularly in the areas that were previously wetted. Therefore, by letter dated November 18, 2010, the staff issued RAI B.2.1.28-3 requesting additional information to determine how the effects of aging for aggregate expansion due to ASR in the concrete containment would be managed so that its intended function will be maintained for the period of extended operation. The staff requested that the applicant provide information about the test method or procedure used to: (1) confirm that the exterior containment concrete surface between elevation
| |
| -30 ft. and +20 ft. is not experiencing cracking due to expansion and reaction of cement paste with aggregates; and (2) verify that the compressive strength and modulus of elasticity of the concrete containment at these elevations are not affected by cracking due to expansion and reaction with aggregates. In addition, the staff requested the applicant to provide results of any existing or planned compressive, tensile, and modulus of elasticity concrete tests of core samples taken from the concrete containment between elevation
| |
| -30 ft. and +20 ft.
| |
| In its response dated December 17, 2010, the applicant stated that the 2010 ASME Code Section XI, Subsection IWL five year inspection of the Containment Structure yielded "no sign of detrimental cracking in the Containment Structure based on the inspection performed using the guidance of ACI 349.3R." The applicant also stated that "[i]n the absence of detrimental cracking, there has been no reasonable expectation for loss of compressive strength or loss of modulus of elasticity." The applicant further stated that it would perform confirmatory testing and evaluation of the containment structure concrete, reflected in its Commitment 51, to "determine the concrete compressive strength, the presence or absence of [ASR], the concrete modulus of elasticity, and the presence or absence of rebar degradation. The testing and evaluation [would] be completed prior to the period of extended operation." In addition, the applicant stated that prior to the period of extended operation it would "implement measures to maintain the exterior surface of the Containment Structure, from elevation
| |
| -30 feet to +20 feet, in a dewatered state." To this end, the applicant proposed a new Enhancement 2 and Commitment 52, reviewed and evaluated above.
| |
| | |
| Aging Management Review Results 3-153 Based on its review, the staff found the applicant's response to RAI B.2.1.28
| |
| -3 concerning confirmatory testing and evaluation of the concrete Containment Structure unacceptable, because Commitment 51, to just perform confirmatory testing and evaluation of the containment structure prior to the period of extended operation (March 15, 2030), would only support Commitment portions of program elements of GALL Report AMP XI.S2, "ASME Section XI, Subsection IWL," with which the applicant professed consistency in the LRA.
| |
| In a letter dated April 14, 2011, the applicant clarified its initial response to RAI B.1.28
| |
| -3 and referenced inspection IP 71002. In its clarification response, the applicant added several rows to Table 2.4
| |
| -2 and AMR items to Table 3.5.2
| |
| -2 in the LRA, for material/environment of concrete in raw water for the containment building. The applicant also stated that the clarification and changes to the LRA were needed to manage the effects of aging of the concrete containment so that its intended function would be maintained consistent with the CLB for the period of extended operation.
| |
| Contrary to the applicant's additional input, also summarized in its response to RAI B.2.1.28
| |
| -3 that there was "no sign of detrimental cracking in the Containment Structure," the staff noted that the IP 71002 inspection report (ADAMS Accession No. ML111360432), dated May 23, 2011, identified weaknesses in the ASME Section XI, Subsection IWL AMPs and the existence of crazed pattern cracking in the annulus area of the containment. In addition, the report documented the lack of existence of a technically acceptable trending system to establish the status of observed cracks (i.e., stable or active). Therefore, by letter dated June 29, 2011, the staff issued Follow
| |
| -up RAI B.2.1.28
| |
| -3 (ADAMS Accession No. ML11178A338) regarding the status of the initial Enhancement 2 and Commitment 51, requesting the existence of plans, if any, to monitor the extent of cracking and expansion of aggregates in concrete. In its response to Follow-up RAI B.2.1.28
| |
| -3, dated August 11,2011, the applicant stated that it deleted its Enhancement 2 and Commitment 51 for confirmatory testing, reviewed and evaluated in (Deleted) Enhancement 2 above, because of its ongoing effort to develop a planned approach to testing and mitigation techniques to be included in an engineering evaluation scheduled to be completed in March 2012.
| |
| In a subsequent letter dated March 30, 2012 (ADAMS Accession No. ML12094A364), the applicant supplemented its initial response to RAI B.2.1.28
| |
| -3 on the testing method or procedure used to identify whether the wetted portion of the containment building structure is experiencing cracking due to ASR, and on past and future testing to verify the concrete strength of the wetted area. The applicant stated that the ASME Code Section XI, Subsection IWL five year inspection of the containment structure was performed in 2010, with additional inspections of the exterior surface of the containment structure performed in September 2011 using the guidance of ACI 349.3R, where no signs of detrimental cracking were found. The applicant also stated that the additional inspections of the exterior surface of the containment structure showed a "maximum crack width of 8 mils, which is less than the 15 mil criteria for acceptance without further evaluation in the first
| |
| -tier of the Structural Monitoring Program. Inspections revealed two isolated locations of the Containment exterior surface that exhibit pattern cracking that may be indicative of ASR." The applicant further stated that:
| |
| Although the identified crack width does not meet the Structural Monitoring Program threshold for further evaluation, these two locations will be included in the second
| |
| -tier evaluation criteria of the program due to the past groundwater Aging Management Review Results 3-154 inleakage and follo w-up inspections will be performed. Any identified crack growth will require additional evaluation.
| |
| The applicant stated that "in the absence of detrimental cracking, there has been no reasonable expectation for loss of compressive strength or loss of modulus of elasticity." However, the applicant stated that it would:
| |
| [P]erform confirmatory testing and evaluation of the Containment Structure concrete. The testing and evaluation will determine the concrete compressive strength, the presence or absence of [ASR], the concrete modulus of elasticity, and the presence or absence of rebar degradation. The testing and evaluation will be completed [and] measures [taken] to maintain the exterior surface of the Containment Structure, from elevation
| |
| -30 feet to +20 feet, in a dewatered state - prior to the period of extended operation.
| |
| Furthermore, the applicant stated that core samples have not been taken for testing and were not planned in the near future, and that indications of cracking were minor.
| |
| The staff reviewed the applicant's responses to RAI B.2.1.28
| |
| -3 and Follow
| |
| -up RAI B.2.1.28
| |
| -3 and found them unacceptable because the applicant had not confirmed if the cracks are passive or active. The applicant stated that the crack pattern might be due to ASR, which is indicative of active cracking. The staff notes that active cracking observed in a structure is required to be investigated because cracking damage can continue or intensify. The staff also notes that the 15 mil crack width acceptance criteria noted in Section 5.1 of ACI 349.3R and referenced in GALL Report AMP XI.S6, "Structures Monitoring Program," is for passive cracks, which are defined as those lacking recent growth and a crack driving or other degradation mechanism.
| |
| By letter dated November 18, 2010, the staff issued RAI B.2.1.28
| |
| -4 requesting that the applicant provide plans and schedules for the following:
| |
| * conducting a baseline inspection of the condition of accessible above
| |
| -grade and below
| |
| -grade portions of the concrete containment in accordance with ACI 349.3R requirements
| |
| * obtaining nondestructive or destructive test data for quantifying the mechanical properties (compressive strength, tensile strength, and modulus of elasticity) of concrete in areas that have experienced cracking due to expansion and reaction with aggregates In its response dated December 17, 2010, the applicant stated that:
| |
| The most recent ASME [Code] Section XI, Subsection IWL examination of Containment concrete was completed in October 2010. This examination of the Containment concrete consisted of General Visual and Detailed Visual examinations consistent with the criteria in ACI 201.1
| |
| -92 and ACI 349.3R
| |
| -02. These two ASME IWL concrete examinations [would] serve as the baseline for future examinations of Containment concrete, which are performed at 5 year intervals. The containment is enclosed by the Containment Enclosure Building, and the inspection is based on one environment which is Air-Indoor Uncontrolled.
| |
| For the requested information on measures that the applicant would take to determine the integrity of the containment concrete and steel reinforcing bars in areas that have experienced Aging Management Review Results 3-155 cracking due to expansion and reaction with aggregates, the applicant stated that such information was provided in its response to RAI B.2.1.28
| |
| -3. The staff identified these previously unresolved issues as OI 3.0.3.2.18
| |
| -1, in its SER with Open Items, issued in June 2012. The staff noted that, as discussed above in Enhancement 2 (Deleted), these issues are now resolved and OI 3.0.3.2.18
| |
| -1 is closed.
| |
| Update to the Operating Experience By letter dated July 20, 2017, the applicant submitted Supplement 56 (ADAMS Accession No. ML17201A036) revising the LRA AMP B.2.1.28 "Operating Experience" program element to include results from its 2016 IWL examination. In the updated operating experience, the applicant stated that observed indications during inspections had no adverse impact on the structural integrity or structural performance of the containment structure and no ASME Code Repair activities were required as a result of the IWL examination. The staff reviewed the applicant's input and noted that in 2010, Seabrook implemented the recommendations of Information Notice (IN) 2010
| |
| -14, "Containment Concrete Surface Condition Examination Frequency and Acceptance Criteria," to visually inspect, identify, track, and evaluate concrete containment deterioration in accordance with ACI 349.3R (referenced also by the plant's current ASME Code, Section XI, IWL
| |
| -2310). The Seabrook lnservice Inspection Reference (ADAMS Accession No. ML 11180A079) and its CISI Plan for IWL, "Examination Category L
| |
| -A Concrete," however, did not appear to provide any specifications for ASME identifier L 1.12, "Concrete Surface Suspect Areas," which would require detailed visual examination. Furthermore, in License Amendment Request 16
| |
| -01, "Request to Extend Containment Leakage Test Frequency" (ADAMS Accession No. ML16095A278), the applicant stated that the CCI "met the action level criterion necessitating a structural evaluation." The staff noted that it needed additional information to understand why, if ASR cracking necessitated a structural evaluation, that those areas were not identified as "Concrete Surface Suspect Areas" in the IWL program.
| |
| By letter dated January 29, 2018 (ADAMS Accession No. ML18026A879), the staff issued RAI B.2.1.28-5 requesting that the applicant provide information regarding why: (1) the plant appears to limit its IWL visual examinations to "general visual," even though the requirements for IWL-2310 call for "detailed visual" examinations to determine the magnitude and extent of deterioration and distress of suspect concrete surface areas; (2) the identified distressed concrete containment surface areas in the referenced LAR above have not been included as surface areas subject to detail visual examination and reported in the operating experience program element of LRA Section B.2.1.28; and (3) areas identified as "Tier 2" or "Tier 3" and requiring measurement of the extent of degradation by CCI and crack width are not being considered "suspect areas" and if so to provide justification for their exclusion.
| |
| In its response dated February 28, 2018, the applicant stated that it performs general visual examinations in sufficient detail and in accordance with the requirements of ASME Code Section XI, IWL
| |
| -2310 and Table IWL
| |
| -2500-1, to assess the general structural condition of the containment and identify areas and types of concrete deterioration and distress, as described in ACI 201.1 and ACI 349.3R. It then follows with Detailed Visual Examinations for noted evidence of pattern cracking on the surface of the concrete, secondary deposits at the pattern cracking location, dark staining adjacent to the cracks, and gel exudation in the cracks. The applicant also stated that these examinations are performed to determine: (1) the magnitude and extent of deterioration or distress of suspect concrete surfaces as identified in ACI 349.3R; Aging Management Review Results 3-156 (2) the condition of concrete surfaces affected by repair/replacement activities prior to pressure testing; and (3) the condition of reinforcing steel exposed as a result of removal of defective concrete during repair/replacement activities. The applicant further stated that results of detailed visual examination are documented and submitted to the Responsible Engineer for evaluation and disposition. Acceptance of surface conditions by examination, evaluation, or repair/replacement follows IWL
| |
| -3200 and IWL
| |
| -3300, when applicable. The applicant then stated that suspect areas identified during the 2010 IWL inspection that required a detailed visual inspection and subsequent engineering evaluation were accepted without an ASME IWL
| |
| -3300 Engineering Evaluation. However, the applicant enhanced (Enhancement 3) the "monitoring and trending," program element of this AMP and committed (Commitment 55) to incorporate all "Concrete Surface
| |
| - Suspect Areas identified from the 2010 and 2016 ASME
| |
| [Code] Section XI, IWL inspections - into the next revision of [its] CISI Plan," by September 1, 2020. The applicant also stated that ASR suspect areas, regardless of their Tier state, are documented as part of IWL examination but evaluated, monitored, and trended in accordance with the Structures Monitoring Program.
| |
| The staff reviewed the response to RAI B.2.1.28
| |
| -5 and found it acceptable because the applicant: (1) performs general visual and detailed visual examinations as required by ASME Code Section XI, Subsection IWL using the guidance of ACI 201.1 and ACI 349.3R to detect, identify, monitor, and trend deteriorated and distressed concrete surface areas for a number of aging effects that include ASR; (2) commits to incorporate identified areas of distress of the concrete containment surface found during its 2010 and 2016 ASME Code Section XI, IWL inspections into its CISI plan; and (3) will document all potential ASR identifications in the IWL database and evaluate these in accordance with the Structures Monitoring Program regardless of their Tier classification. The staff's concern described in RAI B.2.1.28
| |
| -5 is resolved.
| |
| Based on its audit and review of the application, and review of the applicant's responses to RAI B.2.1.28-3, Follow-up RAI 2.1.28
| |
| -3, RAI B.2.1.28
| |
| -4, and RAI B.2.1.28
| |
| -5, the staff finds that the applicant has appropriately evaluated plant
| |
| -specific and industry operating experience, and that operating experience related to the applicant's program demonstrates that the program can adequately manage the effects of aging on SSCs within the scope of the program, and that implementation of the program has resulted in the applicant taking corrective actions.
| |
| UFSAR Supplement. LRA Section A.2.1.28 as amended by letter dated May 15, 2014 (ADAMS Accession No. ML14142A220), provides the UFSAR supplement for the ASME Code Section XI, Subsection IWL AMP. The staff reviewed the amended UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in S RP-LR Table 3.5
| |
| -2. The staff also noted that the applicant committed to enhance the ASME Code Section XI, Subsection IWL AMP prior to entering the period of extended operation with Commitments 31, 52, 55, and 84, which require, respectively:
| |
| * Include the definition for "Responsible Engineer" in its procedure for implementing its ASME Code Section XI, Subsection IWL AMP;
| |
| * Implement measures to maintain the exterior surface of the containment structure, from elevation
| |
| -30 ft. to +20 ft., in a dewatered state. The staff notes that as discussed in Enhancement 2 above, by letter dated February 28, 2018, the applicant stated that Commitment 52 was completed;
| |
| | |
| Aging Management Review Results 3-157
| |
| * Incorporate into the Seabrook CISI Plan ASR suspect concrete surface areas identified during the 2010 and 2016 IWL containment inspections, prior to September 1, 2020; and
| |
| * Evaluate the acceptability of inaccessible areas for structures within the scope of ASME Code Section XI, Subsection IWL AMP.
| |
| The staff finds that the information in the amended UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its audit and review of the applicant's ASME Code Section XI, Subsection IWL Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that their implementation through Commitments 31, 52, 55, and 84 prior to the period of extended operation will make this AMP adequate to manage the applicable aging effects. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.2.18 Structures Monitoring Program Summary of Technical Information in the Application. LRA Section B.2.1.31 describes the existing Structures Monitoring Program as being consistent, with enhancements, with GALL Report AMP XI.S6, "Structures Monitoring Program." In the LRA, the applicant stated that AMP B.2.1.31, "Structures Monitoring Program," is implemented through the Seabrook Maintenance Rule Program and integrates the Masonry Wall Program and RG 1.127, "Inspection of Water
| |
| -Control Structures Associated with Nuclear Power Plants," Program.
| |
| These programs are existing and consistent with the program elements in GALL Report AMP XI.S5, "Masonry Wall Program," GALL Report AMP XI.S6, "Structures Monitoring Program," and GALL Report AMP XI.S7, "RG 1.127, Inspection of Water
| |
| -Control Structures Associated with Nuclear Power Plants," with enhancements.
| |
| In the LRA, the applicant stated that the Structures Monitoring Program includes periodic visual inspections of structures and structural components for the detection of aging effects specific to the particular structure at a frequency determined by the characteristics of the environment in which the structure is located. These inspections are performed at an interval not to exceed 5 years (plus or minus 1 year) for structures in a harsh environment. The applicant also stated that a harsh environment is defined as one that is in an area that is routinely subjected to outside ambient conditions of very high temperature, high moisture or humidity, frequent large cycling of temperatures, frequent exposure to caustic materials, or extremely high radiation levels. Structures not found in areas qualifying as a harsh environment are classified as being in a mild environment and are inspected on a 10
| |
| -year basis. Individuals performing the inspections and interpreting the results have expertise in the design and inspection of steel, concrete, and masonry structures and are either licensed professional engineers experienced in this area or will be working under the direction of a licensed professional engineer with expertise in this area. The applicant further stated that parameters monitored meet the requirements of ACI 349.3R
| |
| -96, "Evaluation of Existing Nuclear Safety
| |
| -Related Concrete Structures," and
| |
| | |
| Aging Management Review Results 3-158 ASCE 11-90, "Guideline for Structural Condition Assessment of Existing Buildings." Identification of concrete deficiencies is based on guidance provided in ACI 201.1R
| |
| -2, "Guide for Making a Condition Survey of Concrete in Service," and acceptance guidelines use a three
| |
| -tier hierarchy similar to that described in ACI 349.3R
| |
| -96 (i.e., acceptable, acceptable with deficiencies, or unacceptable).
| |
| In the LRA, the applicant stated that aggressive subsurface environments are monitored by sampling the groundwater at 5
| |
| -year intervals for chloride concentration, sulfate concentration, and pH. Inaccessible areas, such as buried concrete foundations, will be examined during inspections of opportunity or during focused inspections at 5
| |
| -year intervals. The applicant also stated that, although Seabrook has no block or concrete masonry walls used in Category I structures, masonry walls in structures and buildings (fire pumphouse, nonessential switchgear room, turbine building and yard structure station blackout (SBO)) performing nonsafety
| |
| -related functions are monitored for cracking and evaluated under the Structures Monitoring Program. Periodic visual inspections of water
| |
| -control and flood protective structures are within the scope of the Structures Monitoring Program and are inspected under the Maintenance Rule Program.
| |
| During the course of the staff's review, the applicant submitted amendments to the application, and these are discussed in the staff's evaluation below, as appropriate.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMPs XI.S5, XI.S6, and XI.S7. As discussed in the audit report, the staff confirmed that each element of the applicant's program is consistent with the corresponding element of GALL Report AMPs XI.S5, XI.S6, and XI.S7.
| |
| The staff also reviewed the portions of the "scope of program," "parameters monitored or inspected," and "monitoring and trending" program elements associated with enhancements to determine if the program will be adequate to manage the aging effects for which it is credited. The staff's evaluation of the enhancements follows.
| |
| Enhancement 1. LRA Section B.2.1.31 includes an enhancement to the "scope of program," "parameters monitored or inspected," and "monitoring and trending" program elements. In this enhancement, the applicant stated that it will expand the Structures Monitoring Program procedure to add the following:
| |
| (1) inspection of elastomeric materials for loss of sealing, leakage, and deterioration of CEVA seals; aluminum for cracking; non
| |
| -metallic fireproofing for abrasion and flaking; and Lubrite for distortion (2) inspection of additional locations, including overhead and fuel handling cranes, NUREG
| |
| -0612 cranes, all supports, tanks (1
| |
| -FP-TK-35-A, 1-FP-TK-35-B, 1-FP-TK-36-A, 1-FP-TK-36-B, and 1-AB-TK-29) and their supports and foundations, fire house boiler building, safety- and nonsafety
| |
| -related electrical cable manhole and duct bank yard structures, and opportunistic or focused inspections of below
| |
| -grade and inaccessible concrete at least once every five years (3) ultrasonic testing and evaluation of the internal bottom surface of two fire protection water storage tanks
| |
| | |
| Aging Management Review Results 3-159 For part (1) of this enhancement, the staff finds the addition of the above
| |
| -listed materials to the Structures Monitoring Program acceptable; however, the staff was not clear how visual inspections would detect degradation in elastomeric, aluminum, and non
| |
| -metallic fire proofing materials before a loss of intended function.
| |
| By letter dated April 14, 2011, the applicant modified LRA Table 3.5.2.4 to state that elastomeric roof material inspections will be done by a licensed professional roofing company. Every five years, the contractor will assess the condition of the elastomeric roof material for separation, environmental degradation, and water in
| |
| -leakage due to weathering through physical roof walks and visual inspections. The applicant further stated that, for aluminum and non
| |
| -metallic fire proofing materials, the applicant's inspectors are either licensed professional engineers experienced in this area or individuals working under the supervision of a licensed professional engineer with expertise in the design and inspection of steel, concrete, and masonry structures. The applicant stated that, during these inspections, "aluminum will be visually inspected like all metallic materials (using the material aging effects) while non
| |
| -metallic fire proofing, which is a sprayed on cementitious material, will be examined the same as concrete." The frequency of inspection is based on the environment. Harsh environments inspections will be performed every 5 years while those in mild environments will be every 10 years. The applicant stated that operating experience may increase the frequency of these inspections. The applicant also stated that "the acceptance criteria will be based on the engineering department standard for the Structures Monitoring Program, which describes the aging effects and evaluation criteria based on the ACI 349 three
| |
| -tiered hierarchy and quantitative limits." Finally, the applicant stated that, upon further review of LRA Table 3.5.2.4, AMR item "Miscellaneous Yard Structures
| |
| -Aluminum Station Blackout Structures Exposed To Air
| |
| -Outdoor (External Weather)," was updated to reflect the appropriate aging effect for this component requiring management to be cracking instead of the originally reported crack initiation and crack growth.
| |
| The staff finds the clarifications provided by the applicant acceptable because inspections are performed periodically by professionals following the criteria laid out in the Structures Monitoring Program. The staff's concern regarding how visual inspections would detect degradation in elastomeric, aluminum, and non
| |
| -metallic fire proofing materials before a loss of intended function is resolved.
| |
| For part (2) of this enhancement, the staff was not clear as to whether external coating inspections of tanks were included within the scope of the applicant's Structures Monitoring Program. Therefore, by letter dated November 18, 2010, the staff issued RAI B.2.1.17
| |
| -1, asking the applicant to verify whether the Structures Monitoring Program would also include inspection of tank coatings for tanks 1
| |
| -FP-TK-35-A, 1-FP-TK-35-B, 1-FP-TK-36-A, 1-FP-TK-36-B, and 1-AB-TK-29. In its response dated December 17, 2010, the applicant stated that, in addition to monitoring the aging effects in the tanks, the program would include inspection of the external surfaces of the aboveground tanks for cracking, flaking, or peeling of paint or coatings. Upon review of the applicant's response, the staff was not clear as to the frequency for performing the visual inspection of these tanks. The staff needed additional information to determine whether the applicant intends to follow the Structures Monitoring Program or the Aboveground Steel Tanks Program guidance, which recommends visual inspections at least every 2 years.
| |
| By letter dated April 14, 2011, the applicant supplemented its response to RAI B.2.1.17
| |
| -1. In its letter, the applicant further clarified its response to RAI B.2.1.17
| |
| -1 by stating that the Structures Aging Management Review Results 3-160 Monitoring Program will perform external visual or tactile (where required) surface inspections every five years of the aboveground steel tanks 1
| |
| -FP-TK-35-A, 1-FP-TK-35-B, 1-FP-TK-36-A, 1-FP-TK-36-B, and 1-AB-TK-29 (fire fuel oil, fire water, and auxiliary boiler fuel oil tanks) to address cracking, flaking, or peeling of paint, coatings, sealants, and caulking. Additionally, the Fire Protection Program will visually inspect these tanks quarterly to assess the condition of their coatings. For tanks that have a caulking seal between the tank and the foundation, tactile examination will be performed to evaluate the condition of the caulking per the System Walkdown Engineering Guidelines. In addition, as stated in its March 5, 2014, amendment to the Fire Water System Program, the external surfaces of the fire water storage tanks will be inspected on an annual basis in accordance with NFPA 25 (2011 Edition), Section 9.2.5.5.
| |
| The staff finds the applicant's response acceptable because the applicant will manage potential deterioration of the external surfaces of the aboveground tanks for cracking, flaking, or peeling of paint or coatings and, where applicable, the condition of caulking through three different AMPs-the Structures Monitoring, Fire Protection, and Fire Water System Programs. These programs collectively will ensure that the external surfaces of the fire fuel oil tanks, fire water tanks, and auxiliary boiler fuel oil tanks will be monitored so that the tanks can continue to perform adequately during the period of extended operation. The staff finds the 5
| |
| -year interval for examination of the tanks under the Structures Monitoring Program acceptable because the tanks are also examined under the applicant's Fire Protection and Fire Water System Programs. The frequency of these inspections is consistent with GALL Report AMP XI.M26, Fire Protection Program, and GALL Report AMP XI.M27, Fire Water System Program, as modified by LR-ISG-2012-02. The staff finds the clarifications provided by the applicant acceptable because inspections are performed periodically by professionals following the criteria laid out in the Structures Monitoring Program. The staff's concerns described in RAI B.2.1.17
| |
| -1 are resolved.
| |
| For part (2) of this enhancement, the staff noted that inclusion of opportunistic or focused inspections on a 5
| |
| -year interval addresses GALL Report recommendations for examination of exposed portions of the below
| |
| -grade concrete when excavated for any reason and development of a plant
| |
| -specific AMP for plants with aggressive groundwater and soil that have experienced degradation. However, the staff also noted that the applicant inspected the remaining in
| |
| -scope structures on a 5
| |
| - or 10-year basis, depending on the structure's environment. The staff believes it may be acceptable to inspect structures on an interval greater than 5 years; however, the applicant must provide a list of the structures inspected under the longer interval, along with a description of their environments and justification for the interval extension. Therefore, by letter dated January 5, 2011, the staff issued RAI B.2.1.31
| |
| -5, requesting that the applicant identify the structures that will be inspected on a 10
| |
| -year frequency, along with their environments and a summary of past degradation.
| |
| In its response, dated February 3, 2011, the applicant stated that a harsh environment is an area routinely subjected to outside ambient conditions, high moisture or humidity, very high ambient temperatures or frequent large cycling of temperatures (including freezing and thawing), frequent exposure to caustic materials, or extremely high radiation levels. A mild environment is one that is not harsh. The applicant further stated that, based on ACI 349.3R, the evaluation and inspection frequency varies according to the environment, from 5
| |
| -10 years. In accordance with ACI
| |
| -349.3R, the interior, above
| |
| -grade portions of the following in
| |
| -scope of license renewal structures are in a mild environment and, therefore, subject to a 10
| |
| -year inspection frequency:
| |
| | |
| Aging Management Review Results 3-161
| |
| * the containment enclosure ventilation area
| |
| * the control building
| |
| * the diesel generator building
| |
| * the waste process building and tank farm (selected areas are harsh)
| |
| * the emergency feedwater pumphouse building including pre
| |
| -action valve building
| |
| * the fuel storage building
| |
| * the primary auxiliary building (selected areas are harsh)
| |
| * the turbine generator building
| |
| * the fire pumphouse
| |
| * the steam generator blowdown recovery building
| |
| * the non-essential switchgear building The applicant also stated that it classified the following structures, following ACI
| |
| -349.3R guidance, to be in a harsh environment and, therefore, subject to a 5
| |
| -year inspection:
| |
| * all in-scope below
| |
| -grade structures (interior and exterior)
| |
| * all exterior above grade structures
| |
| * all structures inside primary containment
| |
| * designated areas of the tank farm and of the primary auxiliary building
| |
| * the service water pumphouse
| |
| * the circulating water pumphouse
| |
| * the intake transition structure
| |
| * the discharge transition structure
| |
| * the service water cooling tower revetment The applicant then reiterated that the past degradation of these structures is discussed in the body of the program in the LRA.
| |
| The staff reviewed the applicant's response and found that it needed clarification regarding (1) how frequently the spent fuel pool would be inspected and (2) whether the inspection frequencies outlined in the response applied to all structures within the scope of the Structures Monitoring Program or just concrete components. By letter dated May 10, 2012, the applicant confirmed that the spent fuel pool is an in
| |
| -scope below
| |
| -grade structure and would be inspected on a 5-year frequency and that the inspection frequencies outlined in the RAI response dated February 3, 2011, applied to all in
| |
| -scope structures, regardless of the material. The staff finds the applicant's response acceptable because the applicant confirmed the spent fuel pool is an in-scope below
| |
| -grade structure and would be inspected on a 5
| |
| -year frequency, In addition, it outlined which structures are subject to a 5
| |
| -year or 10
| |
| -year inspection, and it aligned the frequency with that recommended in ACI
| |
| -349.3R, which provides the basis for industry standards. Further, the applicant confirmed that the 5
| |
| -year or 10
| |
| -year inspection frequency based on ACI
| |
| -349.3R applies to all structures within the scope of the Structures Monitoring Program. The staff's concern discussed in RAI B.2.1.31
| |
| -5 is resolved.
| |
| For part (3) of this enhancement, the staff's review of the technical acceptability of the one
| |
| -time UT examination and its comparison to the GALL Report Aboveground Steel Tanks Program recommendations is discussed in the staff's review of the Aboveground Steel Tanks Program in SER Section 3.0.3.2.9.
| |
| | |
| Aging Management Review Results 3-162 The staff finds this enhancement acceptable because, when implemented, this enhancement will (1) prescribe the parameters to be monitored for the component types to be inspected during the period of extended operation and will provide acceptance criteria for inspection of seals, aluminum, non
| |
| -metallic fire proofing, and Lubrite, (2) address the aging management of structures included within the scope of license renewal that are not covered by other structural AMPs, and (3) include one
| |
| -time ultrasonic testing and evaluation of the internal bottom surface of the Fire Protection Storage tanks, consistent with the recommendations in GALL Report AMP XI.M29, "Aboveground Steel Tanks." This enhancement will make the Structures Monitoring Program consistent with the recommendations in the "scope of program,"
| |
| "parameters monitored or inspected," and "monitoring and trending" program elements of GALL Report AMP XI.S6.
| |
| Enhancement 2. LRA Section B.2.1.31 includes an enhancement to the "scope of program" and "parameters monitored or inspected" program elements. In this enhancement, the applicant stated that it will enhance its Structures Monitoring Program procedure to include opportunistic inspections when planning excavation work that would expose inaccessible concrete. Specifically, the applicant will enhance the "Dig Safe" procedure to include opportunistic inspection when planning excavation work. The staff finds this appropriate as it supports the program enhancement for the inspection of inaccessible, belo w-grade concrete due to aggressive groundwater inleakage. The staff finds this enhancement acceptable because, when implemented, this enhancement will ensure that opportunistic or focused inspections of normally inaccessible concrete are performed, when exposed during excavation work.
| |
| Based on its onsite audit and review of the application, the staff finds that elements one through six of the applicant's Structures Monitoring Program, which integrates the Masonry Wall Program and the Inspection of Water
| |
| -Control Structures Associated with Nuclear Power Plants Program, with acceptable enhancements, are consistent with the corresponding program elements of GALL Report AMPs XI.S5, XI.S6, and XI.S7. In addition, the staff reviewed the enhancements associated with "scope of program," "parameters monitored or inspected," and "monitoring and trending," program elements and finds that, when implemented, they will make the AMP adequate to manage the applicable aging effects.
| |
| Operating Experience. LRA Section B.2.1.31 summarizes operating experience related to the Structures Monitoring Program and states that groundwater infiltration through below
| |
| -grade concrete structures has been an issue at Seabrook. Groundwater sampling performed in November 2008 and September 2009 found pH values between 6.01
| |
| -7.51, chloride levels between 19
| |
| -3,900 ppm, and sulfate levels between 10
| |
| -100 ppm, indicating that the groundwater is an aggressive environment. The LRA also states that below
| |
| -grade concrete structures have experienced groundwater infiltration through cracks, capillaries, pore spaces, seismic isolation joints, and construction joints. To stop or reduce the infiltration, various methods have been used but have had only limited success (e.g., dewatering wells and waterproofing agents). The LRA further states that additional testing is planned during the second and third quarters of 2010 in areas that experienced groundwater infiltration to determine its aging effects and the need for additional remedial action. The LRA finally states that visual inspections have been conducted of nonsafety
| |
| -related masonry for indications of cracking and degradation as identified in the "monitoring checklist" of the applicant's Structures Monitoring Program. The condition of water control and flood protection structures has been assessed through visual inspections conducted through the applicant's Structures Monitoring Program.
| |
| Aging Management Review Results 3-163 The staff reviewed the operating experience information, in the application and during the onsite audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program. During its review, the staff identified operating experience that could indicate that the applicant's program may not be effective in adequately managing aging effects during the period of extended operation and needs to be modified to demonstrate that the effects of aging will be adequately managed. The staff determined the need for additional clarification that resulted in the issuance of four RAIs. These are discussed below.
| |
| RAI B.2.1.31
| |
| -1. During the audit walkdown and review of condition reports, the staff noted that groundwater infiltration through below
| |
| -grade concrete walls has been a chronic issue at the plant. The staff also observed indications of leaching and alkali
| |
| -aggregate reactions occurring in the concrete exposed to groundwater infiltration. The staff was unclear if the concrete degradation due to groundwater infiltration had been quantified and how the degradation will be managed during the period of extended operation. To address the groundwater issue, by letter dated November 18, 2010, the staff issued RAI B.2.1.31
| |
| -1, expressing concerns on the effects of infiltration in the concrete structures and requesting that the applicant provide a summary of all concrete mechanical testing performed to date and explain how its results are correlated to the actual plant structures. The staff also asked the applicant to provide the root cause of any reductions in structural capacities and degraded material properties and explain how the followup aging effects would be managed during the period of extended operation.
| |
| In its response dated December 17, 2010, the applicant stated that concrete mechanical testing, performed in May 2010, is only reflective of the location where it was conducted. Specifically, the applicant stated that cores were taken and penetration resistance tests (PRT) were conducted to evaluate the compressive strength of concrete, at elevation
| |
| -20 ft of the "B" Electrical Tunnel. The average compressive strength for the PRT was 5,340 psi and, for the bores, 4,790 psi. The measured strength was approximately 20 percent less than that obtained in earlier years. In particular, the PRT performed in 1979 yielded a compressive strength of 6,759 psi. For the construction test cylinders tested in 1975, the compressive strength was 6,120 psi. Similarly, analysis of current data indicated a reduction in the original modulus of elasticity by about 47 percent. Further, petrographic analysis of the 2010 core samples showed evidence of ASR. The applicant further stated that a prompt operability determination concluded that the areas of concrete on the "B" electrical tunnel affected by ASR comply with the applicable design codes, and the structural integrity of the "B" electrical tunnel is intact with all SSCs housed within the tunnel being operable and capable of performing their design functions. The applicant finally stated that an extent of condition investigation was in progress to test potentially five additional suspect areas (including the containment enclosure building) to obtain supplementary information for the assessment of the plant concrete condition and the cause of its degradation. The Structures Monitoring Program has recognized ACI 349 as a monitoring and inspection standard that will help manage aging effects during the period of extended operation. Identified deficiencies will be evaluated and put into the corrective action program for resolution (i.e., remediation, corrective, and preventive actions) as required, including further structural analysis, if necessary.
| |
| | |
| Aging Management Review Results 3-164 After review of the applicant's response, the staff did not understand what the extent of condition assessment would include and how it would ensure the adequacy of susceptible concrete during the period of extended operation. The response also lacked information regarding approximate completion dates and a probable path forward including the location and timing of future tests and proposed remedial actions. Therefore, by letter dated March 17, 2011, the staff issued a followup RAI to RAI B.2.1.31
| |
| -1, asking the applicant to identify the extent and timeliness of the assessment and anticipated remediation, including the path forward to ensure that the concrete would retain its integrity during the period of extended operation.
| |
| By letter dated April 14, 2011, the applicant responded to the RAI. In the response, the applicant stated that concrete samples had been taken from five additional locations, which were chosen because they exhibited groundwater in
| |
| -leakage and surface cracking indicative of ASR. The applicant further explained that an action plan was being developed to address the ASR degradation. The plan would include multiple activities to include those listed below:
| |
| * identify areas potentially susceptible to ASR
| |
| * complete concrete testing in other susceptible areas to determine compressive strength, modulus of elasticity, and confirm the presence of ASR
| |
| * based on test results, reconcile existing calculations and analyses to ensure structures continue to meet all design basis conditions
| |
| * perform lab tests to determine the rate of the ASR degradation mechanism and how it propagates
| |
| * issue an engineering evaluation addressing ASR, the results of testing, and mitigation techniques
| |
| * update the Structures Monitoring Program to include guidance on monitoring for ASR, including the appropriate frequency of inspection
| |
| * develop a long
| |
| -range plan to implement mitigation techniques to arrest ASR degradation The applicant further stated that the implementation of the action plan was tentatively scheduled to be completed in December 2013. Finally, the applicant stated that the Structures Monitoring Program would be revised to include action for inspection and monitoring of concrete for degradation due to ASR.
| |
| The staff reviewed the applicant's response and found that the response lacked specific information about what tests (laboratory and in
| |
| -situ) would be conducted and when. The response also made no mention of how possible reductions in concrete shear strength were being estimated and addressed. In addition, the RAI response stated that cores were being taken in accordance with ACI 228.1R
| |
| -03; however, it did not address the statistical validity and size of core samples taken or planned at each location. Therefore, by letter dated June 29, 2011, the staff issued follow up RAI B.2.1.31
| |
| -1 requesting the applicant to:
| |
| (1) Explain if the current operability evaluation remains valid until the long
| |
| -term aging management plan is developed and implemented.
| |
| (2) Explain how the concrete tests and evaluations performed so far can be used to establish a trend in degradation of the affected structures until the long
| |
| -term aging management plan is implemented.
| |
| | |
| Aging Management Review Results 3-165 (3) Provide detailed and comprehensive information regarding the planned approach to addressing ASR degradation throughout the site.
| |
| (4) Explain how the possibility of a reduction in shear strength capacity due to ASR degradation is being evaluated.
| |
| By letter dated August 11, 2011, the applicant provided an initial response to the RAI. In this response, the applicant stated that the current operability determination was expected to remain valid but may require modification. The applicant also stated that a comprehensive plan t o evaluate and address ASR concrete degradation, and develop and implement a long
| |
| -term monitoring plan was ongoing and would be included in an engineering evaluation scheduled to be completed by March 2012.
| |
| In a subsequent letter dated March 30, 2012, the applicant stated that it had initiated actions to perform additional testing to demonstrate that the effects of ASR on in
| |
| -scope structures can be managed to maintain the intended functions of the affected structures through the period of extended operation. The applicant also stated that, through this testing, quantitative crack limits would be developed. The crack limits would be incorporated into the Structures Monitoring Program to manage the effects of ASR on concrete structures. The quantitative crack limits would be used to develop acceptance criteria such that corrective action can be implemented prior to loss of intended function. The applicant also submitted another letter on April 18, 2012, in which it stated that the two operability evaluations were revised on October 11, 2011. These revised operability evaluations concluded that the ASR affected structures were fully capable of performing their intended function and operable with reduced margin. The applicant further stated that full qualification would be attained when the testing and analysis plans were completed and the long
| |
| -term resolution is incorporated into the UFSAR and/or other applicable design documents.
| |
| The staff reviewed the applicant's response in the three letters and noted that the applicant plans to enhance the Structures Monitoring Program to manage ASR degradation. However, the enhancements will not be completed until the long
| |
| -term additional testing is completed and quantitative acceptance criteria for crack limits are developed. The staff was concerned that the applicant had not provided the details of the proposed enhancements to the program elements "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria,"
| |
| to the Structures Monitoring AMP to manage the effects of ASR. A revised aging management program with enhancements for managing the ASR degradation, for each in-scope concrete structure, is required to demonstrate that the effects of aging will be maintained consistent with the CLB for the period of extended operation as mandated by 10 CFR 54.21(a)(3). This issue was identified as Open Item OI 3.0.3.2.18
| |
| -1 and has since been resolved and closed based on the staff evaluations in SER Sections 3.0.3.3.6 and 3.0.3.3.7.
| |
| RAI B.2.1.31
| |
| -2. During the audit walkdown and review of condition reports, the staff also noted that groundwater infiltration has caused degradation of internal plant structures and components, such as supports, base
| |
| -plates, cable trays, etc. The staff was unclear how the degradation due to groundwater infiltration will be managed during the period of extended operation (i.e., concerned that the groundwater infiltration may be causing accelerated degradation of plant structures, supports, and components, as noted in the condition reports reviewed during the audit). Therefore, by letter dated November 18, 2010, the staff issued RAI B.2.1.31-2, asking the applicant to explain how internal plant structures exposed to Aging Management Review Results 3-166 groundwater infiltration will be managed for additional or accelerated degradation during the period of extended operation.
| |
| In its response, dated December 17, 2010, the applicant reiterated that components affected by groundwater in
| |
| -leakage are managed through the plant's Structures Monitoring Program, which follows the Structural Engineering Standard Technical Procedure issued in March 2010. The Structures Monitoring Program inspects building structural steel components (e.g., base plates, columns, beams, braces, platforms, cable trays, structural bolting, and fasteners) for corrosion, peeling paint, excessive support deflections, twisting, warping, or locally deflecting beams and columns, loose or missing anchors and fasteners, missing, cracked, or degraded grout under the steel base plates, and cracked welds. The program evaluates and assesses each component's acceptability based on the extent of its degradations and then initiates corrective actions, followed by additional inspections to verify their effectiveness.
| |
| After review of the applicant's response, it was not clear to the staff why, after the update of the procedure in March 2010, there was still degradation due to in
| |
| -leakage witnessed during audit walkdown in October 2010. To this end, by letter dated March 17, 2011, the staff issued a followup RAI to RAI B.2.1.31
| |
| -2, asking the applicant to state what actions will be taken to avert further degradation in areas prone to groundwater in
| |
| -leakage. By letter dated April 14, 2011, the applicant responded to the RAI and stated that deficiencies identified in structural steel during structures monitoring inspections are documented in the inspection reports and evaluated. The applicant further stated that deficiencies that do not meet the acceptance criteria are entered into the corrective action program, and deficiencies that are accepted by engineering review are trended for evidence of further degradation. The applicant also explained that deficiencies being repaired or trended are subject to followup inspections at a maximum frequency of 2.5 years. The applicant also stated that the structures monitoring procedure has been revised to include specific direction regarding monitoring for the presence of water in
| |
| -leakage. The staff reviewed the applicant's response and finds it acceptable because the applicant explained that deficiencies are either repaired or accepted by engineering review. If a condition is accepted by engineering review, the inspection frequency is adjusted accordingly to provide assurance that any further degradation will be properly identified and addressed (e.g., maximum inspection frequency of 2.5 years). This approach is consistent with recommendations in the GALL Report AMP XI.S6 which recommends that aging effects are evaluated by qualified personnel using criteria derived from industry codes and standards contained in the plant current licensing bases, including ACI 349.3R. As recommended in ACI 349.3R, the applicant's inspectors for the Structures Monitoring Program are either licensed professional engineers or individuals working under the supervision of a licensed professional engineer with expertise in the design and inspection of steel, concrete, and masonry structures. These inspectors are qualified and will adjust the inspection frequency depending on the results of the inspection but not more than 2.5 years for structural steel components in the areas of ground water in
| |
| -leakage. This is consistent with the guidance in ACI 349.3R that recommends an increase in frequency of inspection for structures that are found to be degraded beyond acceptance criteria. The staff's concerns described in RAI B.2.1.31
| |
| -2 and followup RAI are resolved.
| |
| RAI B.2.1.31
| |
| -3. During the audit walkdown and review of condition reports, the staff further noted that groundwater infiltration through below
| |
| -grade concrete walls has been a chronic issue at the plant; however, the staff was unable to locate any inspection reports that identified and Aging Management Review Results 3-167 monitored and trended the degradation caused by the infiltration in a quantitative manner. The staff concluded that a baseline quantitative concrete inspection of in
| |
| -scope structures is necessary for monitoring and trending degradation during the period of extended operation. Therefore, by letter dated November 18, 2010, the staff issued RAI B.2.1.31
| |
| -3, requesting that the applicant discuss plans for conducting a quantitative baseline inspection, in accordance with ACI 349.3R, prior to the period of extended operation.
| |
| In its response, dated December 17, 2010, the applicant stated that the Structures Monitoring Program described in LRA Appendix A, Section A.2.1.31, and LRA Appendix B, Section B.2.1.31, has been revised to include the ACI 349.3R guidance for inspections. This is reflected in Supplement 2 of the Seabrook LRA, dated November 15, 2010. The implementing procedure for the Structures Monitoring Program issued in March of 2010 describes the evaluation criteria based on the ACI 349.3R three
| |
| -tiered hierarchy and quantitative limits.
| |
| The staff reviewed the applicant's response and finds it acceptable because the implementing procedure for the program, issued in March 2010, follows the industry
| |
| -defined three
| |
| -tiered ACI 349.3R hierarchical standard (i.e., acceptance without further evaluation, acceptance after review, conditions requiring further evaluation) with quantitative limits. In addition, the new acceptance criteria have already been implemented and are being used during current structural inspections. The staff's concerns described in RAI B.2.1.31
| |
| -3 are resolved.
| |
| RAI B.2.1.31
| |
| -4. During the audit and review of program basis documents, the staff noted that the fuel transfer canal has shown indications of borated water leakage. In order to complete its review, the staff requested additional information on historic and current leakages (values, paths, etc.) and the condition of the affected structures. Therefore, by letter dated November 18, 2010, the staff issued RAI B.2.1.31
| |
| -4, requesting that the applicant discuss the leakage path, current status of leak(s), and any other information to demonstrate that the affected structures will be able to perform their intended functions during the period of extended operation.
| |
| In its response dated December 17, 2010, the applicant itemized historical records dating back to 1999. The response stated that, during that year, the applicant performed a root cause investigation "to identify the source of water in the annulus between the containment building and the containment enclosure building." The applicant stated that as part of the investigation, a leak in the spent fuel pool was identified. The applicant stated that, immediately upon discovery, an enclosed tank was installed in the spent fuel pool leakoff sump to collect new leakage and to protect the sump and the environment from further contamination. Additional actions included protecting foundations and groundwater from contamination with selective dewatering through existing wells and removing leakage from contaminated systems. From 2000-2004, testing and inspection continued in the spent fuel pool, the spent fuel transfer canal, and the cask handling area to identify the source of the leak. In 2004, the applicant installed a nonmetallic liner in an attempt to stop the leakage. The applicant further stated that, by 2004, the leak had stopped in the spent fuel pool (confirmed by the lack of contaminated water in the sump), but water level fluctuations caused the leak in the canal to increase to 350 gallons per day. A 2002 and 2004 chemical analysis of leakage indicated that it is compatible to the water in the spent fuel pool. From 2005
| |
| -2008, the applicant repaired delaminated liner (i.e., coatings) for the spent fuel pool, and since 2006, the applicant has instituted programmatic weekly monitoring of the leakage.
| |
| | |
| Aging Management Review Results 3-168 After review of the applicant's response, it was not clear to the staff whether the applicant has stopped all the leakage and that no through
| |
| -wall leakage is occurring. In addition, based on industry operating experience with failures of spent fuel pool nonmetallic coatings, the staff is not confident that the nonmetallic liner is an appropriate long
| |
| -term fix. To address these issues, by letter dated March 17, 2011, the staff issued a followup RAI to B.2.1.31
| |
| -4, requesting that the applicant discuss the measures to be taken to demonstrate the integrity of the concrete structures exposed to spent fuel pool leakage, including the possibility of core bores from known leakage locations. The staff also requested that the applicant explain its conclusion that no through-wall leakage is occurring at present, especially in inaccessible areas. Furthermore, the staff asked the applicant to demonstrate, if a nonmetallic liner is relied upon to stop leakage, the measures that will be taken to ensure its adequacy during the period of extended operation.
| |
| By letter dated April 14, 2011, the applicant responded to the RAI and stated that a core
| |
| -bore test would be completed no later than December 31, 2015. The test would take place in an area subjected to wetting during the timeframe of the leakage and would test for the compressive strength of the concrete and would expose rebar for detection of any potential loss of material. The applicant further stated that the spent fuel pool leak
| |
| -off system is routinely hydro-lazed to ensure that it is free
| |
| -flowing. The applicant stated that the leak
| |
| -off system is the path of least resistance for any water between the liner plate and the concrete wall, and leakage from the spent fuel pool would drain to the leak collection sump. The sump is periodically sampled and tested for signs of leakage, such as boron and tritium. Finally, the applicant stated that the nonmetallic lining is replaced on the basis of condition monitoring that will identify when the end of life for the material has been reached. The applicant stated that the following activities will be continued during the period of extended operation:
| |
| * monitoring of the liner coating coupon system under the Preventive Maintenance (PM), "Visual Inspection of Coupons Coated with SEFR"
| |
| * continued sampling and analysis of leak system effluent under procedure "Spent Fuel Pool Leakage Collection Program" The staff reviewed the applicant's response but found the response was unclear in identifying where the leakage was coming from and what the leakage values had been historically. In addition, the applicant did not identify how frequently the leak-off system was confirmed to be clear. To clarify these points, the staff held a conference call with the applicant on May 31, 2011. During the conference call, the applicant stated that additional spent fuel pool leakage was detected during the spring 2011 outage. Therefore, to address this additional operating experience, by letter dated June 29, 2011, the staff issued followup RAI B.2.1.31
| |
| -4 requesting that the applicant:
| |
| (1) Provide technical justification for the adequacy of the December 31, 2015, deadline for the spent fuel pool concrete core bore, or provide a new deadline and appropriate justification.
| |
| (2) Identify the frequency that the leak
| |
| -off system is ensured to be free
| |
| -flowing. (3) Provide information on the recent leakage from the spent fuel pool, including the probable leakage path and source; whether the leakage is contained within the leak
| |
| -off system; and whether or not chemical analysis will be performed on leakage during the period of extended operation.
| |
| | |
| Aging Management Review Results 3-169 By letter dated August 11, 2011, the applicant responded to the first request by stating that there is no continuous borated water leakage from the spent fuel pool. Any leakage collects in a catch basin in sump and does not contact concrete. The applicant further committed to confirming the absence of embedded steel corrosion by performing a shallow core sample in an area subjected to wetting during the time frame of the spent fuel pool leakage. Finally, the applicant stated that the December 31, 2015, deadline was acceptable because similar operating experience at other nuclear plants has shown that structural capacity is not significantly affected by exposure to borated water.
| |
| In response to the second request, the applicant stated that hydro
| |
| -lazing is performed on the spent fuel pool leak
| |
| -off lines at a 4.5
| |
| -year frequency, which will be maintained throughout the period of extended operation. The applicant also explained that leak
| |
| -off is recorded once a month and reviewed by the system engineer. Unusual leakage, or lack thereof, could be an indicator of blockage and would be investigated accordingly.
| |
| In response to the third request, the applicant stated that the spent fuel pool leak
| |
| -off is analyzed for gamma and tritium activity. On April 6, 2011, zone 6 of the spent fuel pool leak
| |
| -off system showed a step increase in the tritium activity concentration. The applicant explained that this increase occurred coincident with refilling of the cask loading pool, which had previously been drained. At this point, the leak rate was estimated at 1.2 gal per day (gpd). Subsequent measurements identified a peak leak rate of approximately 2.57 gpd, which decreased to the current level of 0.016 gpd (approximately 2 oz. per day). The applicant further explained that, on average, approximately 10 gpd of groundwater infiltration leaks out of the zone 6 tell
| |
| -tale line. The applicant explained that "[t]he volume of spent fuel pool leakage is estimated by taking the ratio of the leak
| |
| -off line tritium concentration to the pool tritium concentration and multiplying that value by the amount of zone 6 leakage pumped out from the collection tank. In this particular instance, the only leak
| |
| -off line that indicated any leakage was zone 6." The applicant then stated that there are several potential causes for the increased leakage, including a new stainless steel liner plate leak in an area not coated with the non
| |
| -metallic liner; a failure in the non-metallic liner at the same location as a stainless steel liner failure; or a skimmer pit leak. The applicant further stated that these possibilities are being addressed with corrective actions, including verifying the integrity of the cask loading area liner through drain down and inspection, revising procedures for cask filling to limit the pool level, and determining if the current design of the skimmer pits is appropriate or if changes can be made to prevent leakage from the pit. Finally, the applicant committed to analyze spent fuel pool leak
| |
| -off for chlorides, sulfates, pH, and iron for four quarters of 1 year once every 5 years.
| |
| The staff reviewed the applicant's response and was unable to determine the source or flow path of the leakage. In response to the first portion of the followup RAI, the applicant stated that it "does not have continuous borated water leakage from the spent fuel pool"; however, in response to the third portion, the applicant stated "leakage decreased to the current level of 0.016 gpd." Based on this response, it is not clear if the spent fuel pool is leaking. The staff also noted that the applicant committed to monitor the leakage quarterly for chlorides, sulfates, pH, and iron once every 5 years (Commitment 68). This approach is unacceptable (i.e., may not be adequate) for detecting a possible trend that could indicate degradation such as an increase in the iron content of the leakage. The staff provided its concerns to the applicant during an inspection visit the week of September 26, 2011.
| |
| | |
| Aging Management Review Results 3-170 To address these concerns, the applicant supplemented its response to followup RAI B.2.1.31
| |
| -4 by letter dated November 2, 2011. In its response, the applicant explained that the spent fuel pool, cask handling, and fuel transfer canal areas have nine zones that collect leakage. Th e spent fuel pool is separated from the cask handling area and the fuel transfer area by a gate.
| |
| The applicant stated that there have been no incidents of leakage from the spent fuel pool; the only incidents of leakage have been from the cask handling and fuel transfer canal areas. The applicant further stated that zone 6 is the only leakage collection sample line that routinely has water flow, that this zone collects leakage from the cask handling area, and that the majority of the water in the zone 6 sample line is from groundwater in
| |
| -leakage. The applicant further clarified that the leakage detected on April 6, 2011, was from zone 6, which meant it was from the cask handling area and not the spent fuel pool. The applicant also updated Commitment 68 to sample the leak
| |
| -off water once every 3 months.
| |
| The staff reviewed the applicant's supplement and noted that leakage has not occurred from the spent fuel pool; all historic leakage has been from the cask handling and fuel transfer canal areas. The staff also noted that the applicant plans to sample the leak
| |
| -off water quarterly, which provides reasonable assurance that any negative trends in chlorides, sulfates, pH, or iron content that could indicate degradation would be captured in a timely fashion. The staff also reviewed the original RAI and followups dated December 17, 2010, April 14, 2011, and August 11, 2011, and noted that the current leakage is captured within the leak
| |
| -off system and is collected in the spent fuel pool leakage sump. The staff further noted that there has been no operating experience with leakage migrating through the concrete walls, except the leakage identified in 1999, which was leakage out of the sump that had been directed to the sump by the leak-off collection system. Once the spent fuel pool leakage sump was identified as the source of the through
| |
| -wall leakage, a tank was added to the sump, which collects any leak
| |
| -off flow before it potentially contaminates the sump. The staff also noted that, in order to keep the leak
| |
| -off system free
| |
| -flowing, the applicant will hydro
| |
| -laze the lines on a 4.5
| |
| -year frequency and monitor the flow monthly for any indications of blockage. Finally, the staff noted that the applicant committed to take a core bore from the spent fuel pool sump in an area that was exposed to through
| |
| -wall leakage (Commitment 67). The bore will be examined for concrete degradation and will expose the rebar to examine it for any signs of degradation. Based on its review, the staff finds the applicant's response and approach acceptable for the following reasons:
| |
| * The applicant has plans in place to take a core bore from an area that was continuously wetted by borated water. This provides assurance that any degradation that may have occurred in the past will be identified and addressed prior to the period of extended operation.
| |
| * The applicant does not currently have any indications of leakage migrating through the concrete walls of the spent fuel pool (i.e., leakage not captured in the leak
| |
| -off system). This provides assurance that any degradation that may have occurred in the past due to borated water will not continue during the period of extended operation.
| |
| * The applicant has plans in place to maintain the leak
| |
| -off system clear of blockage, which provides assurance that any future leakage will be captured in the system and directed to the sump, as opposed to migrating through the spent fuel pool concrete walls.
| |
| | |
| Aging Management Review Results 3-171
| |
| * The applicant will monitor the chemical properties of the leak
| |
| -off collection on a quarterly basis. Any changes in the chemical makeup of the leak
| |
| -off water could be a sign that the leakage is interacting with the concrete, which may indicate leakage outside of the collection system.
| |
| * The applicant will continue to attempt to locate the leakage source and stop it completely.
| |
| Based on the above, the staff's concern discussed in RAI B.2.1.31
| |
| -4, and the associated followup RAIs, is resolved. By letter dated January 29, 2016 (ADAMS Accession No. ML16035A245), the applicant provided the status of several commitments, including Commitments 67 and 68 related to the spent fuel pool leakage. The letter noted that a core had been taken in accordance with Commitment 67 and that no degradation from boric acid exposure was identified in the concrete or the exposed rebar. The core did show early indications of ASR progression. The letter also noted that a routine preventive maintenance activity was established and started as of January 29, 2014, to conduct quarterly leak
| |
| -off collections and chemical testing from the spent fuel pool, thereby meeting the intent of Commitment 68.
| |
| The staff reviewed the provided information related to Commitments 67 and 68.
| |
| Commitment 67 confirmed that the borated water leakage was not having a structural impact on the spent fuel pool. Although indications of ASR degradation were identified, this will be addressed within the plant
| |
| -specific ASR Monitoring Program. Commitment 68 began tracking the chemical composition of the spent fuel pool leakage and any significant changes will be addressed within the applicant's corrective action program. Significant changes in chemical makeup of the leakage could indicate additional interaction with the concrete or reinforcement, or possibly leakage from a different source. Based on its review, the staff finds that the applicant adequately completed Commitments 67 and 68.
| |
| Alkali-Silica Reaction (ASR). In its June 8, 2012, Safety Evaluation Report with Open Items, the staff identified that the management of expansion due to reaction with aggregates (ASR) had not been sufficiently addressed by the applicant and concluded that the ASR issue was an open item. Following initially proposing to manage cracking due to expansion from reaction with aggregates using the Structures Monitoring Program and ASME Code Section XI, Subsection IWL Program, the applicant subsequently developed plant
| |
| -specific AMPs to manage the effects of ASR on concrete structures. On May 16, 2012, the applicant submitted its plant
| |
| -specific ASR Monitoring Program. The applicant stated that the ASR Monitoring Program will be used to manage the effects of ASR microcracking. On August 9, 2016, the applicant submitted an additional plant
| |
| -specific Building Deformation Monitoring Program to address building deformation and macro cracking due to ASR. The history of the ASR issue, a summary of the staff's RAIs and the applicant's responses, and the staff's evaluation of the applicant's ASR Monitoring Program are in SER Section 3.0.3.3.6. The staff's evaluation of the Building Deformation Monitoring Program is in SER Section 3.0.3.3.7.
| |
| Based on its audit and review of the application, and review of the applicant's responses t o RAIs B.2.1.31
| |
| -2, B.2.31-3, B.2.1.31
| |
| -4, associated follow up RAIs listed in SER Sections 3.0.3.3.6 and 3.0.3.3.7, and the augmentation of the Structures Monitoring Program and the ASME Code Section XI, Subsection IWL Program with the ASR Monitoring Program and Building Deformation Monitoring Program, the staff finds that the applicant has appropriately evaluated plant
| |
| -specific and industry operating experience, and implementation of Aging Management Review Results 3-172 the program has resulted in the applicant taking corrective actions. Based on the staff evaluations documented in SER Sections 3.0.3.3.6 and 3.0.3.3.7, Open Item OI 3.0.3.2.18
| |
| -1 related to managing aging effects due to ASR is closed.
| |
| UFSAR Supplement. LRA Section A.2.1.31 provides the UFSAR supplement for the Structures Monitoring Program.
| |
| In LRA Appendix A, the applicant provided the UFSAR supplement for the Structures Monitoring Program. The staff reviewed this UFSAR supplement and noted that it is consistent with the recommended description in SRP
| |
| -LR Table 3.5
| |
| -2. However, the supplement made no mention of ACI 349.3R, which is an important reference document for the applicant's program. Several of the applicant's program elements were found consistent with the GALL Report recommendations because they followed guidance from ACI 349.3R. This concern was provided to the applicant during the October 2010 audit. By letter dated November 15, 2010, the applicant revised the UFSAR supplement to include ACI 349.3R. The staff also noted that the applicant committed (Commitments 32 and 33) to enhance the Structures Monitoring Program prior to entering the period of extended operation. Specifically, the applicant committed to do the following:
| |
| * enhance the procedure to add the aging effects, additional locations, inspection frequency, and ultrasonic test requirements
| |
| * enhance the procedure to include inspection of opportunity when planning excavation work that would expose inaccessible concrete In addition, the applicant committed (Commitment Nos. 67 and 68) to do the following
| |
| :
| |
| * perform one shallow core bore in an area that was continuously wetted from borated water to be examined for concrete degradation and also exposed rebar to detect any degradation such as loss of material, no later than December 31, 2015
| |
| * perform sampling at the leakoff collection points for chlorides, sulfates, pH, and iron once every 3 months, starting in January 2014 The staff notes that subsequent to the issuance of the SER with Open Items, Commitments 67 and 68 were completed as previously indicated in this SER section. The staff finds that the information in the UFSAR supplement, as amended, is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its audit and review of the applicant's Structures Monitoring Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that their implementation prior to the period of extended operation will make the AMP adequate to manage the applicable aging effects. The ASR Monitoring Program and the Building Deformation Monitoring Program, which are augmentations of the Structures Monitoring Program and the ASME Code Section XI, Subsection IWL Program, are documented in SER Sections 3.0.3.3.6 and 3.0.3.3.7, and based on which Open Item OI 3.0.3.2.18
| |
| -1 is resolved and closed. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff Aging Management Review Results 3-173 also reviewed the UFSAR supplement, as amended, for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.2.19 Inaccessible Power Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements Program Summary of Technical Information in the Application. LRA Section B.2.1.34, as revised by LRA supplement letters dated October 29, 2010, and December 17, 2010, describes the new Inaccessible Power Cables Not Subject To 10 CFR 50.49 EQ Requirements Program as consistent, with an enhancement, with GALL Report AMP XI.E3, "Inaccessible Medium
| |
| -Voltage Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements." The applicant stated that the new program will manage the aging effects of localized damage and breakdown of insulation leading to electrical failure of inaccessible power cables (greater than or equal to 400 V) due to adverse localized environments caused by exposure to significant moisture regardless of frequency of energization. The applicant also stated that an adverse localized environment for inaccessible power cables is defined as periodic exposures to moisture that lasts more than a few days (e.g., cable in standing water). The applicant further stated that the applicant's Inaccessible Power Cables Not Subject To 10 CFR 50.49 EQ Requirements Program includes periodic and event
| |
| -driven inspection of manholes containing in-scope inaccessible power cables and draining water, as needed. The applicant stated that the maximum time between inspections will be no more than 1 year, but the frequency will be based on plant
| |
| -specific operating experience with cable wetting or submergence, with the first inspections completed prior to the period of extended operation. In addition, the applicant stated that in-scope inaccessible power cables are tested to provide an indication of the condition of the conductor insulation with testing performed prior to the period of extended operation and at least every 6 years thereafter.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP XI.E3. As discussed in the audit report, the staff confirmed that these elements are consistent with the corresponding elements of GALL Report AMP XI.E3.
| |
| The staff also reviewed the portions of the "scope of program," "parameters monitored or inspected," and "detection of aging effects" program elements associated with the enhancement to determine if the program will be adequate to manage the aging effects for which it is credited. The staff's evaluation of this enhancement follows.
| |
| Enhancement 1. During the audit, the staff was concerned that the applicant's AMP may not be consistent with GALL Report AMP XI.E3 or SRP
| |
| -LR Section A.1.2.3.10 in that, as additional operating experience is obtained, lessons learned are evaluated and the program adjusted as required. Specifically, the application of GALL Report AMP XI.E3 to inaccessible medium voltage cable was based on operating experience available at the time Revision 1 of the GALL Report was developed. Recently identified industry operating experience indicates that the presence of water or moisture can be a contributing factor in inaccessible power cable failures at lower service voltages (400 V to 2 kv). Further, industry operating experience, provided by NRC applicants in response to GL 2007
| |
| -01, "Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients," has shown that Aging Management Review Results 3-174 there is an increasing trend of cable failures with length in service beginning in the 6th through 10th years of operation and that moisture intrusion is a predominant factor contributing to cable failure. Industry operating experience has also shown that some NRC applicants may experience events, such as flooding or heavy rain, that subjects cables within the scope of program for GALL Report AMP XI.E3 to significant moisture.
| |
| In response to the staff's concern, the applicant stated during the audit that the Inaccessible Power Cables Not Subject To 10 CFR 50.49 EQ Requirements Program and associated UFSAR supplement would be revised to address the staff concerns regarding more recent industry operating experience.
| |
| The applicant revised LRA Section B.2.1.34 by letters dated October 29, 2010, and December 17, 2010, which provided an enhancement to "scope of program," "parameters monitored or inspected," and "detection of aging effects." The enhancement expanded the Inaccessible Power Cables Not Subject To 10 CFR 50.49 EQ Requirements Program to include all inaccessible power cables (including de
| |
| -energized cable) greater than or equal to 400 V within the scope of license renewal and subject to significant moisture. In addition, although not specifically identified as an enhancement or exception, the applicant also revised the cable manhole inspection frequency from a maximum time between inspections of no more than 2 years to no more than 1 year. In addition to periodic inspections, the applicant also revised the LRA to include inspections for ev ent-driven occurrences (e.g., rain or flood). The applicant also revised the cable testing frequency from at least every 10 years to at least every 6 years.
| |
| The staff finds that, with the enhancements and revised inspection and testing intervals specified in the LRA supplements dated October 29, 2010, and December 17, 2010, there is reasonable assurance that the applicant's Inaccessible Power Cables Not Subject To 10 CFR 50.49 EQ Requirements Program will adequately manage the aging effects of inaccessibl e power cables. The applicant's program addresses industry operating experience consistent with current staff and SRP
| |
| -LR Section A.1.2.3.10 guidance. The staff concerns identified in the audit report are resolved.
| |
| Based on its audit, and review of the applicant's LRA including supplements dated October 29, 2010, and December 17, 2010, the staff finds that elements one through six of the applicant's Inaccessible Power Cables Not Subject To 10 CFR 50.49 EQ Requirements Program, with acceptable enhancement, are consistent with the corresponding program elements of GALL Report AMP XI.E3 and industry operating experience.
| |
| Operating Experience. LRA Section B.2.1.34 as revised by LRA supplement dated October 29, 2010, summarizes operating experience related to the Inaccessible Power Cables Not Subject To 10 CFR 50.49 EQ Requirements Program.
| |
| The applicant stated that the GALL Report was considered as part of its operating experience review through the September 2005 issue date of GALL Report, Revision 1. In its response to GL 2007-01, the applicant concluded that no failures have occurred in power cables within the scope of the maintenance rule. The applicant also noted that, based on operating experience, it has maintained an inspection of 10 percent of the safety-related manholes every 5 years since 1994. The applicant also stated that a 2009 fleet procedure was issued that provided dewatering for electrical cables with the strategy that all cables important to generation and nuclear safety are to be maintained in a dry (not submerged) condition. The applicant further stated that it is in the process of implementing this fleet procedure. The applicant stated that it Aging Management Review Results 3-175 performed inspections in late 2009 and early 2010 of all safety
| |
| -related manholes and removed water from the manholes. The applicant further stated that the inspection frequency was increased to prevent submergence of safety
| |
| -related cables and that it has performed tests on all safety-related, inaccessible, in
| |
| -scope, greater than or equal to 400 V power cables and the nonsafety-related medium voltage cables with the test acceptance criteria met.
| |
| The staff reviewed the operating experience, in the application and during the audit, to determine if the applicable aging effects and industry and pl ant-specific operating experience were reviewed by the applicant. As discussed in the audit report, the staff conducted an independent search of the plant operating experience including manhole inspection and cable test information to determine if the applicant adequately incorporated and evaluated operating experience related to this program. Further, the staff performed a search of regulatory operating experience for the 10 years through April 2010. Databases were searched using various key word searches and then reviewed by technical auditor staff. The staff walked down selected in
| |
| -scope manholes during the audit and noted limited water accumulation with no cable submergence noted.
| |
| During the audit, the staff identified industry operating experience, which could indicate that the applicant's program may not be effective in adequately managing aging effects during the period of extended operation. The staff determined the need for additional clarification concerning more recent industry operating experience. To resolve the staff's concerns, the applicant provided LRA supplements dated October 29, 2010, and December 17, 2010, which included an enhancement of the Inaccessible Power Cables Not Subject To 10 CFR 50.49 EQ Requirements Program. The enhancement increased the scope of the program to include in
| |
| -scope inaccessible cable greater than or equal to 400 V (energized or deenergized) subject to significant moisture. Additional program revisions included increasing the manhole inspection frequency to a maximum time between inspections of 1 year and changing the cable testing frequency to at least once every 6 years. To account for event
| |
| -driven occurrences such as heavy rain or flooding, the applicant also included event
| |
| -driven inspections for cable manholes. With the included enhancement and additional changes to the applicant's Inaccessible Power Cables Not Subject To 10 CFR 50.49 EQ Requirements Program, the applicant's program is consistent with recent industry
| |
| - and plant-specific operating experience and current staff guidance. The staff concerns identified during the audit are resolved.
| |
| Based on its audit, review of the application, and review of the applicant's LRA supplements dated October 29, 2010, and December 17, 2010, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.34 provides the UFSAR supplement for the Inaccessible Power Cables Not Subject To 10 CFR 50.49 EQ Requirements Program.
| |
| The staff reviewed the UFSAR supplement description of the program, as revised by letters dated October 29, 2010, and December 17, 2010, and noted that it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Table 3.6
| |
| -2. As part of the applicant's LRA supplements, the applicant revised LRA Section A.2.1.34 to do the following:
| |
| | |
| Aging Management Review Results 3-176
| |
| * add in-scope low-voltage power cable (greater than or equal to 400 V)
| |
| * eliminate the criterion that exempts cables when not energized 25 percent of the time
| |
| * revise inspections and test frequencies
| |
| * include event
| |
| -driven inspections due to event
| |
| -driven occurrences such as heavy rain or flooding The staff also noted that the applicant committed (Commitment 36) to implement the new Inaccessible Power Cables Not Subject To 10 CFR 50.49 EQ Requirements Program prior to the period of extended operation for managing aging of applicable components.
| |
| The staff determined that the information in the UFSAR supplement, as amended, is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its audit and review of the applicant's Inaccessible Power Cables Not Subject To 10 CFR 50.49 EQ Requirements Program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are consistent. Additionally, the staff finds the program's enhancement to incorporate greater than or equal to 400 V in-scope inaccessible power cable to be consistent with industry operating experience. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.2.20 Protective Coating Monitoring and Maintenance Program Summary of Technical Information in the Application. By letter dated November 15, 2010, the applicant submitted an LRA supplement that included LRA Section B.2.1.38 which describes the existing Protective Coating Monitoring and Maintenance Program as consistent, with enhancements, with GALL Report AMP XI.S8, "Protective Coating Monitoring and Maintenance Program." The applicant stated that the program manages cracking, blistering, flaking, peeling, and delamination of the Service Level 1 coatings, consistent with the guidelines of Regulatory Position C4 of the NRC RG 1.54, Revision 1, "Quality Assurance Requirements for Protective Coatings Applied to Water
| |
| -Cooled Nuclear Power Plants," as described in NUREG
| |
| -1801, Revision 1.
| |
| The applicant stated that, at the beginning of every RFO, the NextEra Energy coating supervisor and the design engineer inspect all areas and components from which peeling coatings have the potential of falling into the reactor cavity or emergency core cooling system (ECCS) recirculation sumps. It was indicated that after completion of all containment closeout work, the coating supervisor shall notify the design engineer and the nuclear coating specialist to perform the containment closeout inspection, and unqualified coatings found during this inspection shall be evaluated based on size, location, and coating type. The applicant further stated that, based on the results of this evaluation, the unqualified coating shall be removed as directed by the design engineer or documented on the containment coatings closeout inspection form and on an action request.
| |
| The applicant stated that the program requires that all accessible areas of containment receive a coatings inspection of all Service Level 1 coatings. It was reported that these inspections are Aging Management Review Results 3-177 performed during each RFO by qualified coatings inspectors. The applicant stated that the coatings inspectors are qualified per the requirements of ANSI N45.2.6, "Qualification of Inspection, Examination, and Testing Personnel."
| |
| The applicant stated that the coatings used in Service Level 1 applications were qualified and applied in accordance with the requirements of the following documents:
| |
| * NRC RG 1.54, "Service Level I, II, III, and In
| |
| -Scope License Renewal Protective Coatings Applied to Nuclear Power Plants"
| |
| * ANSI N101.4
| |
| -1972, "Quality Assurance for Protective Coatings Applied to Nuclear Facilities"
| |
| * ANSI N101.2
| |
| -1972, "Protective Coatings (Paints) for Light Water Nuclear Containment Facilities"
| |
| * ANSI N512-1974, "Protective Coatings (Paints) for the Nuclear Industry" The applicant indicated that the determination of acceptability of the coatings will be made by qualified inspection personnel. The applicant reported that the inspection personnel determination, as well as any deteriorated or unqualified coatings identified, will be documented in the as-left action request.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's Service Level 1 coatings qualification. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff evaluated the information provided by the applicant and determined that the application of the Protective Coatings Monitoring and Maintenance Program is acceptable in managing coating degradation since the program is consistent with GALL Report Section XI.S8.
| |
| The staff finds the frequency of coating inspections to be acceptable since inspecting every RFO would provide adequate assurance that there is proper maintenance of the protective coatings. The method of performing the coatings inspection is acceptable since the staff has found acceptable that visual inspections are performed and are able to detect for adverse coating conditions such as blistering, cracking, flaking, rusting, checking, insufficient adhesion, undercutting, peeling, and other signs of distress. The staff also found acceptable the manner in which the programs meet the requirements of ANSI N101.4
| |
| -1972, N101.2-1972, and N512
| |
| -1974, since it is consistent with NRC RG 1.54. In addition, the qualification of personnel who perform the inspection is found to be acceptable since the staff has reviewed and confirmed that ANSI N45.2.6 is acceptable.
| |
| The staff also reviewed the portions of the "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements associated with enhancements to determine if the program will be adequate to manage the aging effects for which it is credited. The staff's evaluation of these enhancements follows.
| |
| Enhancement 1. LRA Section B.2.1.38 states an enhancement to the "detection of aging effects" program element. The applicant stated that the program will be enhanced by designating and qualifying an inspection coordinator and an inspection results evaluator.
| |
| | |
| Aging Management Review Results 3-178 On the basis of its review, the staff finds this enhancement acceptable because, when it is implemented, prior to the period of extended operation, it will make the program consistent with the recommendations of GALL Report AMP XI.S8.
| |
| Enhancement 2. LRA Section B.2.1.38 states an enhancement to the "detection of aging effects" program element. The applicant stated that the program will be enhanced to include instruments and equipment needed for inspection (i.e., flashlight, spotlights, marker pen, mirror, measuring tape, magnifier, binoculars, camera with or without wide angle lens, self
| |
| -sealing polyethylene sample bags).
| |
| On the basis of its review, the staff finds this enhancement acceptable because, when it is implemented, prior to the period of extended operation, it will make the program consistent with the recommendations of GALL Report AMP XI.S8.
| |
| Enhancement 3. LRA Section B.2.1.38 states an enhancement to the "monitoring and trending," program element. The applicant stated that the program will be enhanced to include a review of the previous two monitoring reports.
| |
| The staff notes that the frequency of monitoring reports are completed during the coating inspections every RFO and would provide adequate assurance that the protective coatings are being trended for degradation. The method of performing the coatings inspection, as described above, is to do visual inspections which detect for adverse coating conditions such as blistering, cracking, flaking, rusting, checking, insufficient adhesion, undercutting, peeling, and other signs of distress.
| |
| On the basis of its review, the staff finds this enhancement acceptable because it is consistent with ASTM D 5163 which specifies a review of the previous two monitoring reports (two previous RFOs) and when the enhancement is implemented, prior to the period of extended operation, it will make the program consistent with the recommendations in GALL Report AMP XI.S8. Enhancement 4. LRA Section B.2.1.38 states an enhancement to the "acceptance criteria" program element. The applicant stated that the program will be enhanced to include a requirement for the inspection report to be evaluated by responsible evaluation personnel who are to prepare a summary of findings and recommendations for future surveillance or repair. On the basis of its review, the staff finds this enhancement acceptable because, when it is implemented, prior to the period of extended operation, it will make the program consistent with the recommendations in GALL Report AMP XI.S8.
| |
| Based on its audit and review of the application, the staff finds that program elements one through six of the applicant's Protective Coating Monitoring and Maintenance Program, with acceptable enhancements, are consistent with the corresponding program elements of GAL L Report AMP XI.S8 and, therefore, are acceptable.
| |
| Operating Experience. LRA Section B.2.1.38 summarizes operating experience related to the Protective Coating Monitoring and Maintenance Program. The applicant states that the program is an existing program that is used to identify degraded or deteriorated Service Level 1 coatings.
| |
| The applicant provided the following information regarding operating experience:
| |
| | |
| Aging Management Review Results 3-179 (1) In June 2010, an Action Request (AR) was issued to review NRC Information Notice IN 2010-12-Containment Liner Corrosion. The NRC issued this IN to inform addressees of recent issues involving corrosion of the steel reactor containment building liner. The AR response addressed all the concerns identified by the IN 2010
| |
| -12. The AR concludes that: i) Seabrook Station Containment structure is enclosed by a reinforced seismic category I concrete enclosure building which prevents exterior containment concrete from exposure to external atmosphere; ii) during construction at Seabrook Station there were three independent levels of Quality Control that provided assurance that adequate concrete placement techniques were implemented which eliminated the possibility of foreign material (organic compounds) being introduced during the concrete placement; and iii) the last IWE inspections of the containment liner performed at the Seabrook Station concluded that there were minor imperfections and discoloration in the coating film and isolated areas where the coating had been damaged, exposing the liner steel which contained only rust staining, or minor surface corrosion. In general, there was no measurable corrosion or any metal loss detected in the containment liner steel. (2) In October 2010, an AR identified failure and degradation of Reactor Sump Liner Coating of the Unit 3 Reactor Sump Liner Plate at Turkey Point Nuclear Station.
| |
| NextEra is in the process of evaluating this current AR for applicability at Seabrook.
| |
| (3) In December 1997, a Condition Report (CR) identified containment liner paint (approximately two square feet) scraped off at the scaffold storage area during the refueling outage OR05, due to poor material control practices for storing the scaffolding material. Paint in this area and other additional areas listed in the work order were repaired.
| |
| (4) In July 1998 Seabrook personnel performed a review of NRC Generic Letter GL 98
| |
| -04, "Potential for Degradation of the Emergency Core Cooling System (ECCS) and the Containment Spray System (CSS) After a Loss
| |
| -of-Coolant (LOCA) Accident Because of Construction and Protective Coating Deficiencies and Foreign Material in Containment." Seabrook Station responded to GL 98
| |
| -04 via letter NYN
| |
| -98125. The staff reviewed the operating experience information in the application to determine if the applicable aging effects and industry
| |
| - and plant-specific operating experience were reviewed by the applicant and are evaluated in the GALL Report. During its review, the staff found no operating experience to indicate that the applicant's program would be ineffective in adequately managing aging effects during the period of extended operation.
| |
| Based on its review of the application, the staff finds that operating experience related to t he applicant's program demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the application taking appropriate corrective actions. The staff confirmed that the "operating experience" program satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.1.38 provides the UFSAR supplement for the Protective Coating Monitoring and Maintenance Program. The staff reviewed the UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Table 3.5
| |
| -2.
| |
| Aging Management Review Results 3-180 The staff also noted that the applicant committed (Commitment Nos. 46, 47, 48, and 49) to enhance the Protective Coating Monitoring and Maintenance Program prior to entering the period of extended operation. Specifically, the applicant committed to do the following:
| |
| (1) Enhance the program by designating and qualifying an Inspection Coordinator and an Inspection Results Evaluator.
| |
| (2) Enhance the program to include instruments and equipment needed for inspection (i.e., flashlight, spotlights, marker pen, mirror, measuring tape, magnifier, binoculars, camera with or without wide angle lens, self
| |
| -sealing polyethylene sample bags).
| |
| (3) Enhance the program to include a review of the previous two monitoring reports.
| |
| (4) Enhance the program to include a requirement that the inspection report be evaluated by the responsible evaluation personnel, who is to prepare a summary of findings and recommendations for future surveillance or repair.
| |
| The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its review of the applicant's Protective Coating Monitoring and Maintenance Program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the enhancements and confirmed that their implementation through Commitment Nos. 46, 47, 48, and 49 prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it was compared. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(2). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides and adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.2.21 Metal Fatigue of Reactor Coolant Pressure Boundary Program Summary of Technical Information in the Application. LRA Section B.2.3.1 describes the existing Metal Fatigue of Reactor Coolant Pressure Boundary Program as consistent, with enhancements, with GALL Report AMP X.M1, "Fatigue Monitoring Program." The applicant's program is a preventive measure to mitigate fatigue cracking of RCPB components by monitoring and tracking critical thermal and pressure transients for selected RCS components. This ensures the number of design transient cycles is not exceeded during the operating life and the cumulative usage factor (CUF) for these components remains less than 1.0. The applicant stated that the fatigue
| |
| -sensitive components include locations such as the reactor vessel shell and lower head; reactor vessel inlet and outlet nozzles; pressurizer surge line (hot leg and pressurizer nozzles); reactor coolant piping charging system nozzle; reactor coolant piping SI nozzle; and RH system Class 1 piping. The applicant also stated that the environmental effects for the fatigue
| |
| -sensitive components specified in the NUREG/CR
| |
| -6260, "Application of NUREG/CR
| |
| -5999 Interim Fatigue Curves to Selected Nuclear Power Plant Components," report for newer vintage Westinghouse plants have been addressed in LRA Section 4.3. Four of these components will be monitored by the applicant's program for fatigue usage, including environmental effects. These components are pressurizer surge line (hot leg and pressurizer nozzles); reactor coolant piping charging system nozzle; reactor coolant piping Aging Management Review Results 3-181 SI nozzle; and RH system Class 1 piping, analyzed in accordance with ASME Code Section III, Subsection NB
| |
| -3200. The applicant also stated that pre
| |
| -established cycle limits would identify components approaching design limits. Corrective actions for components approaching design limits include reanalysis; inspection and flaw tolerance evaluation; and repair or replace, in accordance with applicable design codes. The applicant further stated that Seabrook will enhance the Metal Fatigue of Reactor Coolant Pressure Boundary Program to include additional transients beyond those defined in the TS and the UFSAR and to use a software program to count transients to monitor cumulative usage on select components.
| |
| During the course of the staff's review, the applicant submitted amendments to the application, and these are discussed in the staff's evaluation below, as appropriate.
| |
| Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by the conditions for which the GALL Report was evaluated.
| |
| The staff compared elements one through six of the applicant's program to the corresponding elements of GALL Report AMP X.M1. As discussed in the audit report, the staff confirmed that each element of the applicant's program is consistent with the corresponding element of GALL Report AMP X.M1, with the exception of the "scope of program," "parameters monitored or inspected," "detection of aging effects," and "acceptance criteria" program elements. For these elements, the staff determined the need for additional clarification, which resulted in the issuance of RAIs.
| |
| In its review the staff noted that the scope of the applicant's program includes nuclear steam supply system (NSSS), non
| |
| -NSSS components, and transients in UFSAR Section 3.9.1.1 that require tracking. LRA Section 4.3 states that the metal fatigue time
| |
| -limited aging analyses (TLAAs) that are evaluated in the LRA fall into the following categories:
| |
| (a) Explicit fatigue analyses for NSSS pressure vessel and components that were prepared in accordance with ASME Code Section III, Class A or Class 1 rules, developed as part of the original design.
| |
| (b) Supplemental explicit fatigue analyses for piping and components that were prepared in accordance with ASME Code Section III rules to evaluate transients that were identified after the original design analyses were completed. Such analyses include consideration of pressurizer surge line thermal stratification and reactor vessel internal (RVI) component fatigue analyses.
| |
| (c) New fatigue analyses (also in accordance with ASME Code Section III, Class 1 rules) prepared for license renewal to evaluate the effects of the reactor water environment on the sample of high fatigue locations applicable to newer vintage Westinghouse Plants, as identified in Section 5.5 of NUREG/CR
| |
| -6260, and using the methodology presented in LRA Section 4.3.4.
| |
| In addition, LRA Section 4.3.1 states that the most limiting number of transients used in these NSSS component analyses are shown in LRA Table 4.3.1
| |
| -2, and are considered to be design limits. The staff confirmed that these transients are consistent with those listed in UFSAR Table 3.9(N)-1.
| |
| Aging Management Review Results 3-182 The staff noted that LRA Table 4.3.1
| |
| -2 lists more plant design transients than those identified in TS 5.7 and TS Table 5.7
| |
| -1. For example, in the TS table, normal condition transients include only plant heatup and shutdown. Upset transients include only loss of load without turbine roll, loss of all offsite power, partial loss of flow, and reactor trip from full power. Faulted transients include large steam line break, and test transients include primary and secondary side hydrostatic test and primary side leak test. It was not clear to the staff if the design CUF fatigue analyses for NSSS pressure vessels and components were based on the design transients listed in TS Table 5.7
| |
| -1 or the non
| |
| -TS transients that were included in LRA Table 4.3.1
| |
| -2 and UFSAR Table 3.9(N)
| |
| -1. For those transients listed in LRA Table 4.3.1-2 but not in the TS, it was not clear to the staff how a transient will be accounted for, in accordance with the applicant's program during the period of extended operation. The staff noted that the "parameters monitored/inspected" program element of GALL Report AMP X.M1 states that the program monitors all plant transients that cause cyclic strains, which are significant contributors to the fatigue usage factor. By letter dated December 14, 2010, the staff issued RAI B.2.3.1
| |
| -1, requesting that the applicant clarify whether the "category (a)" fatigue analysis and the "category (b)" supplemental fatigue analysis were based on transients from TS Table 5.7
| |
| -1 or LRA Table 4.3.1
| |
| -2 and in UFSAR Table 3.9(N)
| |
| -1. The staff also asked the applicant to confirm that the plant
| |
| -specific cycle
| |
| -counting procedure ensures that those design transients listed in LRA Table 4.3.1
| |
| -2 but not in TS 5.7 will be tracked and monitored (i.e., counted) in accordance with the Metal Fatigue of Reactor Coolant Pressure Boundary Program during the period of extended operation. In addition, the staff requested that, if these transients are not monitored during the period of extended operation, the applicant should justify with respect to the "parameters monitored/inspected" program element. In its response dated January 13, 2011, the applicant stated that the "category (a)" fatigue analysis and the "category (b)" supplemental fatigue analysis were based on transients listed in LRA Table 4.3.1
| |
| -2, and the cycle
| |
| -counting procedure tracks and monitors design transients listed in this table and not those listed in TS 5.7. In response to RAI B.2.3.1
| |
| -3, the applicant provided an enhanced LRA Table 4.3.1
| |
| -2 detailing the current and future proposed monitoring of design transients. The additional design transients listed in the enhanced Table 4.3.1
| |
| -2 are monitored by the Metal Fatigue and Reactor Coolant Pressure Boundary Program through the plant's engineering procedure for cycle
| |
| -counting. The applicant further stated that the FatiguePro automated cycle-counting module will be used in companion to this procedure to count, categorize, and record the plant transients listed in the last column of enhanced LRA Table 4.3.1
| |
| -2. In addition, consistent with the applicant's Commitment 41, normal, upset, and test condition transients defined in the TS and UFSAR will be monitored during the period of extended operation. The "initial and random steady
| |
| -state fluctuations and boron concentration equalization" transients are not currently counted or proposed to be counted during the extended period because they are considered to be insignificant stress events, and their number of actual transients is not expected to approach the analyzed number of cycles. The staff finds this acceptable because the stress levels due to these transients would be below the endurance limit; therefore, it can be assumed that the number of allowed cycles is infinite. The applicant further added that emergency and faulted condition transients listed in LRA Table 4.3.1-2 are not required to be included in the fatigue evaluations and, therefore, are also not monitored by the Metal Fatigue and Reactor Coolant Pressure Boundary Program. The staff finds this acceptable. Since the faulted transients are not included in the fatigue calculations, Aging Management Review Results 3-183 they do not have an effect on the calculated fatigue usage and, therefore, do not require monitoring to ensure the design limit of 1.0 is not exceeded.
| |
| Based on its review, the staff finds the applicant's response to RAI B.2.3.1
| |
| -1 acceptable because the applicant clarified that the fatigue analyses were based on transients listed in LRA Table 4.3.1
| |
| -2 and not in TS Table 5.7
| |
| -1. The applicant also enhanced LRA Table 4.3.1
| |
| -2 listing all the transients that are being monitored (or will be monitored) during the period of extended operation by the Metal Fatigue and Reactor Coolant Pressure Boundary Program. Furthermore, the applicant is monitoring all cyclic
| |
| -strain causing transients that are significant contributors to the fatigue usage factor and have been included in the applicant's fatigue analyses, consistent with the recommendations in the "parameters monitored/inspected" program element of GALL Report AMP X.M1. The staff's concern described in RAI B.2.3.1
| |
| -1 is resolved.
| |
| In its review, the staff further noted that the scope of the applicant's program includes both NSSS and non
| |
| -NSSS components as well as transients in UFSAR Section 3.9.1.1 that are required to be tracked. The applicant stated that the most limiting numbers of transients used in these NSSS component analyses are shown in LRA Table 4.3.1
| |
| -2 and are considered to be design limits. However, the staff noted that the transients are termed differently in the LRA, UFSAR, and relevant documents that were reviewed during the staff's audit. For example, upset condition transients such as "inadvertent startup of an inactive loop" or "inadvertent emergency core cooling system actuation" are referred to differently in these documents. The staff also noted during its audit that the applicant's program basis document includes auxiliary transients such as "charging and letdown flow shutoff and return" or "letdown flow step decrease and return." However, these transients are not included in the list of design transients provided in LRA Table 4.3.1
| |
| -2. By letter dated December 14, 2010, the staff issued RAI B.2.3.1
| |
| -2, asking the applicant to do the following:
| |
| * justify the difference of designations for the transients between LRA Table 4.3.1
| |
| -2 and the CUF analyses in the applicant's program basis document
| |
| * clarify and justify how the Metal Fatigue of Reactor Coolant Pressure Boundary Program and the associated onsite procedure will be capable of tracking transient occurrences to ensure that the design limit of 1.0 is not exceeded and that any assumptions that are made in the fatigue CUF analyses remain valid, if the designations for the transients are not consistent between the LRA, the UFSAR, and other relevant documents
| |
| * clarify the significance of the auxiliary transients used in fatigue CUF analyses and explain how these transients are accounted for by the list of design transients provided in LRA Table 4.3.1
| |
| -2 In its response dated January 13, 2011, the applicant acknowledged several wording differences between the transient designation listed in LRA Table 4.3.1-2 and those defined in the UFSAR Section 3.9(N).1.1 and program basis document. The applicant stated that the differences fall into the following categories:
| |
| * differences in the use of abbreviations and combining of symmetric transients such as unit loading and unloading of 5 percent of full power per minute
| |
| | |
| Aging Management Review Results 3-184
| |
| * addition of supplementary auxiliary transients necessary for the fatigue design basis for the chemical and volume control system (CVCS) components
| |
| * several fatigue
| |
| -insignificant plant transients such as steady
| |
| -state fluctuations and boron concentration equalization that are omitted from the fatigue monitoring basis document The applicant further added that the first column of the enhanced LRA Table 4.3.1
| |
| -2 lists all the transients that are included in the Fatigue Management Program and used in the fatigue analyses of the Class 1 components. The Fatigue Management Program will ensure that all fatigue-analyzed components remain within their respective design fatigue analyses results (i.e., CUF less than 1.0) by ensuring that the counted plant transients remain within the number of occurrences of each plant transient listed in the second column of enhanced LRA Table 4.3.1
| |
| -2. The applicant also clarified that the six auxiliary transients listed in the enhanced Table 4.3.1
| |
| -2 with footnote (6) are listed in the design specification for defining fatigue transients for CVCS components and are identified and counted in the FatiguePro software as part of the Metal Fatigue of Reactor Coolant Pressure Boundary Program.
| |
| Based on its review, the staff finds the applicant's response to RAI B.2.3.1
| |
| -2 acceptable because the applicant did the following:
| |
| * clarified the differences in the designations of the transients
| |
| * described how the Metal Fatigue of Reactor Coolant Pressure Boundary Program and Fatigue Management Program track transient occurrences
| |
| * explained the significance of the auxiliary transients used in the fatigue analyses In addition, the applicant's program will ensure that all fatigue
| |
| -analyzed components remain below the design limit of 1.0 by ensuring that the counted plant transients remain within the number of occurrences the component was analyzed for, consistent with the recommendations of GALL Report AMP X.M1. The staff's concern described in RAI B.2.3.1
| |
| -2 is resolved.
| |
| In its review, the staff noted that LRA Section B.2.3.1 states that the Metal Fatigue of Reactor Coolant Pressure Boundary Program monitors and tracks the number of transient cycles to ensure that the CUF for selected RCS components remains less than 1.0 through the period of extended operation. The applicant also stated the program ensured the environmental effect on fatigue sensitive locations are addressed. Locations with CUF approaching the design limit are reanalyzed, inspected, repaired, or replaced, as necessary, in accordance with applicable design codes. LRA Section B.2.3.1 states that pre
| |
| -established action limits will permit completion of corrective actions before the design basis number of events is exceeded and before the CUF, including environmental effects, exceeds the ASME Code limit of 1.0.
| |
| However, it was not clear to the staff if the Metal Fatigue of Reactor Coolant Pressure Boundary Program will perform cycle
| |
| -counting, cycle
| |
| -based fatigue monitoring, or stress-based fatigue monitoring for RCPB components (including the environmentally
| |
| -assisted fatigue (EAF)). Furthermore, the Metal Fatigue of Reactor Coolant Pressure Boundary Program does not provide details regarding the action limits that are set on design basis transient cycle
| |
| -counting activities or on CUF monitoring activities. It also did not provide the corrective actions that will be implemented if an action limit for cycle
| |
| -counting or CUF monitoring is reached. By letter dated December 14, 2010, the staff issued RAI B.2.3.1
| |
| -4, asking the applicant to define and Aging Management Review Results 3-185 justify the "action limit or limits" that will be used by the Metal Fatigue of Reactor Coolant Pressure Boundary Program for the following:
| |
| * design basis CUF values for Class 1 components and any non
| |
| -Class 1 components evaluated to Class 1 component CUF requirements
| |
| * environmentally
| |
| -assisted CUF for the program's NUREG/CR
| |
| -6260 equivalent or bounding locations
| |
| * Class 1 components that are within the scope of the applicant's high
| |
| -energy line break (HELB) analyses for Class 1 components In its response dated January 13, 2011, the applicant stated that the action limit for components for which CUF values are evaluated against a design limit of CUF=1.0 is 80 percent of the design or analyzed number of occurrences for any plant transient included in the fatigue analysis of any of these fatigue
| |
| -analyzed components with or without EAF analysis. For any plant transient included in the fatigue analysis of the EAF-analyzed HELB components, the action limit for components, for which CUF values are evaluated against a design limit of CUF=0.1, is 80 percent of the analyzed number of occurrences. The applicant added that when any one or more of these plant transients reach a value of 80 percent or more of the design number of occurrences, a re
| |
| -evaluation of each of the components analyzed for the plant transient(s) that have achieved their 80
| |
| -percent limit will be performed. Also, the re
| |
| -evaluation may take advantage of use of 60
| |
| -year projected cycles for other transients that are included in the fatigue analysis of each of the affected components.
| |
| Based on its review, the staff finds the applicant's response to RAI B.2.3.1
| |
| -4 acceptable because the action limits are set such that corrective actions can be taken prior to the cumulative fatigue usage of these components exceeding the design limit of 0.1 for HELB locations and 1.0 for all other locations, consistent with the recommendations of GALL Report AMP X.M1. The staff's concern described in RAI B.2.3.1
| |
| -4 is resolved.
| |
| The staff further noted that the "corrective actions" program element in GALL Report X.M1 states that acceptable corrective actions include repair of the component, replacement of the component, and a more rigorous analysis of the component to demonstrate that the design code limit will not be exceeded during the period of extended operation. However, LRA Section B.2.3.1 states that corrective actions may encompass one of several activities below:
| |
| * reanalyze affected component(s) for an increase in the number of a specific transient while accounting for other component
| |
| -affecting plant transients that may be projected not to achieve their analyzed levels
| |
| * perform a fracture mechanics evaluation of a postulated flaw in affected plant components, which, when coupled with an Inservice Inspection Program, will serve to demonstrate flaw tolerant behavior
| |
| * repair the affected component
| |
| * replace the affected component By letter dated December 14, 2010, the staff issued RAI B.2.3.1
| |
| -5, requesting that the applicant justify its corrective action alternative, to perform a fracture mechanics evaluation, which is not Aging Management Review Results 3-186 consistent with the recommendations of the "corrective actions" program element of GALL Report AMP X.M1.
| |
| In its response dated January 13, 2011, the applicant stated that GALL Report AMP X.M1 does not specifically address the use of a fracture mechanics evaluation to reanalyze affected components. However, the ASME Code Section XI, Appendix L, provides guidance for methods for performing fatigue assessments to determine acceptability for continued service of RCS and pressure boundary components subjected to thermal and mechanical fatigue loads. The applicant further stated that the ASME Code specified two methods for performing fatigue assessments
| |
| -a fatigue usage factor evaluation and a flaw tolerance evaluation (using fracture mechanics techniques). Furthermore, these two evaluation methods are the analytical options provided in LRA Section B.2.3.1. The applicant added that the use of the flaw tolerance evaluation method would require NRC approval of fatigue crack growth curves used in the analysis.
| |
| Based on its review, the staff finds the applicant's response to RAI B.2.3.1
| |
| -5 acceptable because Appendix L of ASME Code Section XI specifies that a fatigue usage factor evaluation and a flaw tolerance evaluation using fracture mechanics techniques can be used for performing fatigue assessments, and the applicant's use of a flaw tolerance evaluation method would require NRC review and approval of the fatigue crack growth curves used in the analysis.
| |
| By letter dated May 8, 2013, the applicant supplemented its response by removing the option of performing a fracture mechanics evaluation as a corrective action alternative in LRA Section B.2.3.1. Furthermore, by letter dated July 2, 2013, the applicant made the corresponding revision to LRA Section A.2.4.2.3 to remove the option of performing a fracture mechanics evaluation. Based on its review, the staff finds the applicant's responses to RAI B.2.3.1
| |
| -5 acceptable because the applicant clarified which corrective actions may be taken prior to reaching the design limit of 1.0. The applicant's proposed corrective actions
| |
| -to repair or replace the component or perform a more rigorous analysis for the component to demonstrate that the design limit will not be exceeded
| |
| -are consistent with the recommendations in GALL Report AMP X.M1. The staff's concern described in RAI B.2.3.1
| |
| -5 is resolved.
| |
| The staff also reviewed the portions of the "scope of program," "parameters monitored or inspected," "monitoring and trending," and "acceptance criteria" program elements associated with enhancements to determine if the program will be adequate to manage the aging effects for which it is credited. The staff's evaluation of these enhancements follows.
| |
| Enhancement 1. LRA Section B.2.3.1 states an enhancement to the "parameters monitored or inspected" program element. The applicant stated that its program will be enhanced to include additional transients beyond those defined in the TS and the UFSAR. The staff reviewed this enhancement and noted that the Metal Fatigue of Reactor Coolant Pressure Boundary Program does not identify these additional design transients that are monitored beyond those defined in the TS and the UFSAR. The staff also noted that the applicant's program does not provide any description or the significance of these additional transients. The applicant's program also does not identify the components that these additional transients affect, specifically those CUF TLAAs in LRA Section 4.3 that the applicant dispositioned under 10 CFR 54.21(c)(1)(iii). By letter dated December 14, 2010, the staff issued RAI B.2.3.1
| |
| -3 requesting that the applicant to identify all additional design transients that are monitored by the Metal Fatigue of Reactor Coolant Pressure Boundary Program, justify why these additional transients need to be Aging Management Review Results 3-187 monitored, and provide a discussion of the significance of these additional transients to the TLAAs identified in LRA Section 4.3. The staff also asked the applicant to clarify how these additional transients relate to TS 5.7 and the transients analyzed for in UFSAR Section 3.9. Additionally, the staff asked the applicant to clarify whether these transients were included in the new EAF analysis evaluations that were prepared for license renewal in LRA Section 4.3.4. If they were not included, the applicant must justify why these transients are significant only for those analyses in the CLB and not significant for the analyses performed for the period of extended operation.
| |
| In its response dated January 13, 2011, the applicant included an enhanced LRA Table 4.3.1
| |
| -2, which provides the additional design transients that will be monitored by the Metal Fatigue of Reactor Coolant Pressure Boundary Program through its plant
| |
| -specific procedure for documentation of design operating transients. The applicant added that the additional transients are postulated in the design basis calculations but have not been included in the TS 5.7 and UFSAR Section 3.9. Also, the additional transients have been included in the EAF evaluations presented in LRA Section 4.3.4.
| |
| The applicant further stated that the LRA Section 4.3.1 has been revised to include the enhanced LRA Table 4.3.1
| |
| -2 to identify transients that will be monitored by the Metal Fatigue of Reactor Coolant Pressure Boundary Program. The applicant also stated that the FatiguePro automated cycle
| |
| -counting module will be used as a companion to this procedure to count, categorize, and record the plant transients listed in the last column of the enhanced LRA Table 4.3.1-2. The applicant stated that the additional design transients are selected to record a comprehensive set of plant transients for the purpose of assuring that plant operation remains within the fatigue design bases of the important plant components and to provide plant operational data, should it be necessary to reanalyze plant components in the future.
| |
| The staff noted that the "parameters monitored/inspected" program element of GALL Report AMP X.M1 states that the program monitors all plant transients that cause cyclic strains, which are significant contributors to the fatigue usage factor.
| |
| Based on its review, the staff finds the applicant's response to RAI B.2.3.1
| |
| -3 acceptable because the applicant provided the enhanced LRA Table 4.3.1
| |
| -2 clarifying all the transients that are being monitored or will be monitored during the extended period by the Metal Fatigue and Reactor Coolant pressure Boundary Program. Additionally, the applicant is monitoring those additional transients that are postulated in the design basis calculations, which contribute to fatigue usage, consistent with recommendations of the "parameters monitored/inspected" program element of GALL Report AMP X.M1. Also, the applicant clarified that EAF analysis, performed to address the effects of reactor water environment on component fatigue life, consistent with the recommendations of GALL Report AMP X.M1, have included these additional transients. The staff's concern described in RAI B.2.3.1
| |
| -3 is resolved.
| |
| During its review of LRA Section 4.6.2, the staff noted that the personnel airlock and equipment hatch are designed to 120 heatup and cooldown cycles. The staff also noted that the applicant dispositioned this TLAA in accordance with 10 CFR 54.21(c)(1)(i), that the analyses will remain valid for the period of extended operation. The applicant's basis for this conclusion was provided in LRA Table 4.3
| |
| .1-3, which shows that the 60
| |
| -year projected number of heatups and cooldowns is 87 and 84, respectively. The applicant stated that the anticipated cycles for the personnel airlock and equipment hatch projected to occur during the period of extended Aging Management Review Results 3-188 operation is bounded by the original design of 120 heatup and cooldown cycles. The staff noted in LRA Table 4.3.1
| |
| -2 the limiting design basis number of occurrences for plant heatups and cooldowns is 200 each. The staff further noted that the applicant's Fatigue Monitoring Program tracks plant transients and triggers corrective actions or re
| |
| -evaluation of fatigue analyses when and if the plant approaches the design basis limit of 200 heatup or cooldown cycles but the LRA does not explain if the program will trigger corrective actions if the plant approaches 120 cycles, which is the design limit for the personnel airlock and equipment hatch.
| |
| In a conference call on November 22, 2011, the staff inquired how the applicant will track design limits related to plant startups and shutdowns as listed in LRA Section 4.6.2 related to the personnel airlock and equipment hatch. The staff noted that as previously noted in the applicant's response to RAI B.2.3.1
| |
| -3 and RAI B.2.3.1
| |
| -4 (Reference 3) the design limit tracked by FatiguePro is 200 plant heatups and cooldowns with an 80
| |
| -percent trigger level for further evaluation. The staff noted that this action limit would exceed the design limit of 120 heatup and cooldown cycles for the personnel airlock and equipment hatch as specified in LRA Section 4.6.2. By letter dated December 15, 2011, the applicant stated that it has revised LRA Table 4.3.1
| |
| -2 previously submitted in response to RAI B.2.3.1
| |
| -3 to include the specific plant startup and shutdown design limit of 120 cycles for the Personnel Airlock and Equipment Hatch. In addition, cycle counting for these specific components will initiate appropriate evaluations through the corrective action program if the 80
| |
| -percent action limit is reached and that this limit will be used by the Metal Fatigue of Reactor Coolant Pressure Boundary Program for all limits tracked in FatiguePro. The applicant stated that this action limit will provide sufficient margin and time to allow for appropriate corrective actions as defined in the Metal Fatigue of Reactor Coolant Pressure Boundary Program to be implemented prior to reaching the design limit. The staff reviewed the revised LRA Table 4.3.1
| |
| -2 and confirmed that the applicant included a separate line item with a design limit of 120 cycles, which is specific only to the personnel airlock and equipment hatch analysis.
| |
| The staff noted that the applicant confirmed that there were no additional non
| |
| -conservative design limits utilized in TLAA other than the plant heatups and cooldowns used in the analysis for the personnel airlock and equipment hatch.
| |
| The staff finds the applicant's supplement acceptable because (1) the applicant's Metal Fatigue of Reactor Coolant Pressure Boundary Program ensures that the design cycles (120 plant heatups and cooldowns) that were used in the fatigue analysis for the personnel airlock and equipment hatch will not be exceeded during the period of extended operation; (2) the program ensures sufficient time for corrective actions to be taken (i.e., reanalysis of the component, repair or replacement of the component) with an 80-percent action limit on the design cycles; and (3) the applicant confirmed that there are no other analyses that contain more limiting number of cycles that need to be incorporated into the Metal Fatigue of Reactor Coolant Pressure Boundary Program.
| |
| Based on its review, the staff finds Enhancement No. 1 acceptable because the applicant will monitor these additional transients from its design basis calculations, which are not included in TS 5.7 and UFSAR Section 3.9, consistent with the "parameters monitored/inspected" program element of GALL Report AMP X.M1.
| |
| | |
| Aging Management Review Results 3-189 Enhancement 2. LRA Section B.2.3.1 states an enhancement to the "scope of program," "parameters monitored or inspected," "monitoring and trending," and "acceptance criteria" program elements. The applicant stated that its program will be enhanced to use a software program to count transients to monitor cumulative usage on selected components.
| |
| The "detection of aging effects" program element of GALL Report AMP X.M1 states that the AMP provides periodic update of the fatigue usage calculations. LRA Section B.2.3.1 also states that "[t]he program includes generation of a periodic fatigue monitoring report, including a listing of transient events, cycle summary event details, cumulative usage factors, a detailed fatigue analysis report, and a cycle projection report." However, the staff noted that the LRA does not provide the details regarding the software package that will be used. It is not clear to the staff if the "program" being referred to is the Metal Fatigue of Reactor Coolant Pressure Boundary Program or the software program. It is also not clear to the staff if the software package will be used for cycle
| |
| -counting only or if it will also be used for cycle
| |
| -based or stress
| |
| -based fatigue analysis and includes periodic CUF updates.
| |
| By letter dated December 14, 2010, the staff issued RAI B.2.3.1
| |
| -6, requesting that the applicant do the following:
| |
| * clarify, in detail, how the selected software package will be capable of monitoring those transients that are significant to fatigue usage such that the design limit of 1.0 is not exceeded during the period of extended operation, consistent with the recommendations in GALL Report AMP X.M1
| |
| * clarify how the software package will perform periodic CUF updates, consistent with the recommendations of the "detection of aging effects" program element of GALL Report AMP X.M1
| |
| * clarify how the software package, referenced in LRA Section B.2.3.1 and Commitment 42, addresses and resolves the issue associated with NRC RIS 2008
| |
| -30, "Fatigue Analysis of Nuclear Power Plant Components" In its response dated January 13, 2011, the applicant stated that the EPRI FatiguePro software is used to perform the following functions to accommodate fatigue monitoring of fatigue
| |
| -critical components:
| |
| * The data acquisition system module collects plant instrument data for selected time periods.
| |
| * The automated cycle
| |
| -counting module analyzes the collected plant instrument data and identifies, counts, categorizes, and records pre
| |
| -defined plant transients with their pertinent engineering parameters.
| |
| * The cycle-based fatigue module calculated cumulative fatigue usage for selected plant components by applying counted plant transients to the component design stress report fatigue analysis.
| |
| The applicant also stated that the FatiguePro software would be used in conjunction with its plant-specific cycle
| |
| -counting procedure to provide the technical basis and data for monitoring the number of occurrences and severity of the plant transients that define the fatigue design basis for fatigue
| |
| -critical components. In addition, the data would be used to assure that the Aging Management Review Results 3-190 number and severity of the counted plant transients remain bounded by the component design analyses and, thereby, provide assurance that the design fatigue usage limit of 1.0 is maintained.
| |
| The applicant clarified that, as discussed above, the EPRI FatiguePro cycle
| |
| -based fatigue program calculates cumulative fatigue usage for selected plant components by applying counted plant transients to the component design stress report fatigue analysis. The applicant added that the CUF computation is used as a secondary method for detecting aging effects due to fatigue; cycle
| |
| -counting is the primary method for detecting aging effects.
| |
| The applicant also addressed the staff's concern in NRC RIS 2008
| |
| -30, "Fatigue Analysis of Nuclear Power Plant Components," regarding the use of simplifying assumptions when performing new ASME Code Section III NB-3200 fatigue analyses. The staff's concern is that simplification of the six
| |
| -stress tensor state to fewer stress components in the course of the fatigue analysis may lead to non
| |
| -conservative fatigue usage results and should be benchmarked to six
| |
| -stress tensor analyses whenever this simplification is used. The applicant clarified that the simplified method was used only in the stress
| |
| -based fatigue module of the current FatiguePro software and, to resolve and address this issue, its Metal Fatigue of Reactor Coolant Pressure Boundary Program would not use the simplified FatiguePro stress
| |
| -based fatigue module.
| |
| Based on its review, the staff finds the applicant's response to RAI B.2.3.1
| |
| -6 acceptable for the following reasons:
| |
| * The applicant counts, categorizes, and records the plant transients with FatiguePro in order to ensure that the design limit of 1.0 is not exceeded and the number and severity of the counted plant transients are bound by the component design analyses.
| |
| * The applicant's Metal Fatigue of Reactor Coolant Pressure Boundary Program will periodically calculate fatigue CUF by applying counted plant transients to the component design stress report fatigue analysis, consistent with the "detection of aging effects" program element of GALL Report AMP X.M1.
| |
| * The applicant confirmed that the simplified method used only in the FatiguePro stress
| |
| -based module will not be used in its Metal Fatigue of Reactor Coolant Pressure Boundary Program.
| |
| The staff's concern described in RAI B.2.3.1
| |
| -6 is resolved. The staff reviewed GALL Report AMP X.M1 and noted the following:
| |
| * The "scope of program" program element states that it includes preventive measures to mitigate fatigue cracking of metal components of the RCPB caused by anticipated cyclic strains in the material.
| |
| * The "parameters monitored/inspected" program element states the number of plant transients that cause significant fatigue usage for each critical RCPB component is to be monitored.
| |
| * The "monitoring and trending" program element states that the applicant will monitor a sample of high fatigue usage locations.
| |
| | |
| Aging Management Review Results 3-191
| |
| * The "acceptance criteria" program element states that it involves maintaining the fatigue usage below the design code limit.
| |
| Based on its review, the staff finds Enhancement 2 acceptable because the applicant's program, when enhanced, include preventive measures to mitigate fatigue cracking by monitoring plant transients that cause significant fatigue usage on a sample set of high fatigue usage locations and maintain usage below the design limit of 1.0 by counting transients to monitor cumulative usage on selected components with a software package, consistent with the recommendations of GALL Report AMP X.M1.
| |
| Based on its audit, review of the application, and review of the applicant's responses to RAIs B.2.3.1
| |
| -1 to B.2.3.1
| |
| -6, the staff finds that elements one through six of the applicant's Metal Fatigue of Reactor Coolant Pressure Boundary Program, with acceptable enhancements, are consistent with the corresponding program elements of GALL Report AMP X.M1 and, therefore, are acceptable.
| |
| Operating Experience
| |
| . LRA Section B.2.3.1 summarizes operating experience related to the Metal Fatigue of Reactor Coolant Pressure Boundary Program. The applicant presented several examples that demonstrate that the applicant's program can effectively manage the aging effects of fatigue damage by using industry information to identify fatigue sensitive locations and assure that the CUF meets the acceptance criterion of less than 1.0 during the period of extended operation. In 1989, the applicant responded to the NRC Bulletin 88-11, "Pressurizer Surge Line Thermal Stratification," by reviewing the pressurizer surge line temperature and displacement data, collected during the first operating cycle, to analyze and demonstrate the acceptability of the fatigue CUF analysis for the surge line. Also, in 1988, the applicant evaluated the possibility and effects of fluid leakage in four piping sections in the high head safety injection lines and three piping sections in charging system lines that were un
| |
| -isolable from the RCS and pressurized by the charging pumps. The applicant concluded that these piping sections were not subject to stresses due to thermal stratification or temperature oscillations resulting from the mechanism described in NRC Bulletin 88
| |
| -08, "Thermal Stresses in Piping Connected to Reactor Coolant Systems." In addition, in order to support the 60
| |
| -year TLAAs associated with metal fatigue of the RCS pressure boundary, the applicant analyzed the projected CUF, incorporating environmental effects for seven locations specified in NUREG/CR
| |
| -6260, and found that the CUFs (when including environmental effects) for the surge line hot
| |
| -leg nozzle and the charging nozzle will exceed 1.0 for 60 years of service. The staff noted that these analyses for the surge line hot
| |
| -leg nozzle and the charging nozzle are dispositioned in accordance with 10 CFR 54.21(c)(1)(iii) and will be managed by the applicant's Metal Fatigue of Reactor Coolant Pressure Boundary Program.
| |
| The staff reviewed operating experience information, in the application and during the audit, to determine if the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated operating experience related to this program. During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects Aging Management Review Results 3-192 of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.3.1 provides the UFSAR supplement for the Metal Fatigue of Reactor Coolant Pressure Boundary Program. The staff reviewed this UFSAR supplement description of the program and noted that it conforms to the recommended description for this type of program, as described in SRP
| |
| -LR Table 4.3
| |
| -2. The staff also noted that the applicant committed (Commitment Nos. 41 and 42) to enhance the Metal Fatigue of Reactor Coolant Pressure Boundary Program prior to entering the period of extended operation. Specifically, the applicant committed to the following enhancements, respectively:
| |
| * enhance the program to include additional transients beyond those defined in the TSs and the UFSAR
| |
| * enhance the program to implement a software program to count transients to monitor cumulative usage on selected components The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its audit and review of the applicant's Metal Fatigue of Reactor Coolant Pressure Boundary, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that their implementation through Commitment Nos. 41 and 42 prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it was compared. The staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.3 Aging Management Programs Not Consistent with or Not Addressed in the GALL Report In LRA Appendix B, the applicant identified the following AMPs as plant
| |
| -specific:
| |
| * Buried Piping and Tanks Inspection Program
| |
| * 345 kV SF 6 Program
| |
| * Boral Monitoring Program
| |
| * Nickel-Alloy Nozzles and Penetrations Program
| |
| * PWR Vessel Internals Program
| |
| * Alkali-Silica Reaction Monitoring Program (in response to RAI)
| |
| For AMPs not consistent with or not addressed in the GALL Report, the staff performed a complete review to determine their adequacy to monitor or manage aging. The staff's review of these plant
| |
| -specific AMPs is documented in the following sections.
| |
| | |
| Aging Management Review Results 3-193 3.0.3.3.1 Buried Piping and Tanks Inspection Program Summary of Technical Information in the Application. LRA Section B.2.1.22, as amended by letters dated October 7, 2016, November 23, 2016, and January 3, 2017, describes the new Buried Piping and Tanks Inspection program as plant
| |
| -specific. The applicant stated that the program will include preventive measures, including coating, cathodic protection, and backfill quality to mitigate corrosion and periodic inspections that manage the effects of aging. The applicant also stated that the program will include buried pipe, which is in direct contact with soil; underground pipe, which is located below grade within a vault that is exposed to air
| |
| -indoor uncontrolled and where access is restricted; and inaccessible submerged pipe, which is located below grade within a vault that is in contact with raw water. There are no in
| |
| -scope buried tanks.
| |
| Staff Evaluation. The Buried Piping and Tanks Inspection Program has been significantly revised from the version that was submitted in the LRA and revised through several RAIs. The staff's evaluation of the originally proposed program and applicant's responses to RAIs dated through April 5, 2011, is documented in the Safety Evaluation Report with Open Items Related to the License Renewal of Seabrook Unit 1 (SER with Open Items) dated June 8, 2012. By letters dated July 2, 2013, October 21, 2013, and June 24, 2014, the applicant amended its Buried Piping and Tanks Inspection Program to address LR
| |
| -ISG-2011-03, "Changes to the Generic Aging Lessons Learned (GALL) Report Revision 2 Aging Management Program (AMP)
| |
| XI.M41, 'Buried and Underground Piping and Tanks'," which was issued in its final version on August 2, 2012. By letter dated October 7, 2016, the applicant subsequently amended its Buried Piping and Tanks Inspection Program to address LR
| |
| -ISG-2015-01, "Changes to Buried and Underground Piping and Tank Recommendations" which replaces GALL Report AMP XI.M41, "Buried and Underground Piping and Tanks," and the associated UFSAR summary description issued in LR
| |
| -ISG-2011-03. The staff is not providing an evaluation of the July 2, 2013, October 21, 2013, and June 24, 2014, letters because the changes in these letters became irrelevant with the issuance of the October 7, 2016, letter. The staff reviewed the applicant's claim of consistency with the GALL Report in lieu of the generic guidance provided in SRP
| |
| -LR Section A.1.2.3. The staff compared program elements 1 through 7 of the applicant's program to the corresponding program elements of GALL Report AMP XI.M41, as modified by LR
| |
| -ISG-2015-01. For the "scope of program," "parameters monitored or inspected," "detection of aging effects," and "acceptance criteria" program elements, the staff determined the need for additional information, which resulted in the issuance of RAIs, as discussed below.
| |
| The staff reviewed the "scope of program" program element and noted that it was unclear if copper alloy greater than15
| |
| -percent zinc is included within the scope of the Buried Piping and Tanks Inspection program due to conflicting wording in the LRA. By letter dated November 14, 2016, the staff issued RAI B.2.1.22
| |
| -1, Part 3, requesting that the applicant state if copper alloy greater than 15
| |
| -percent zinc is included within the scope of the Buried Piping and Tanks Inspection program and revise the LRA as appropriate.
| |
| In its response dated November 23, 2016, the applicant stated that the composition of the in
| |
| -scope component is aluminum bronze that they have characterized as copper alloy greater than 15-percent zinc. The applicant revised the LRA to include components of copper alloy greater than 15-percent zinc within the scope of the Buried Piping and Tanks Inspection program. During its review, the staff noted that it was unclear if the number of inspections of components Aging Management Review Results 3-194 of copper alloy greater than 15
| |
| -percent zinc is dependent on the effectiveness of the cathodic protection system. The staff and the applicant conducted a conference call on December 6, 2016, to discuss the staff's concern.
| |
| The applicant agreed to clarify the number and periodicity of planned inspections of components of copper alloy greater than 15
| |
| -percent zinc as a supplement to the application. The staff concluded that the aging effects for components of aluminum bronze and copper alloy greater than 15
| |
| -percent zinc are similar (i.e., loss of material due to pitting and crevice corrosion and selective leaching (if the aluminum content exceeds 8 percent)).
| |
| By letter dated January 3, 2017, the applicant revised its Buried Piping and Tanks Inspection Program to indicate that (a) there is one in
| |
| -scope copper alloy greater than 15
| |
| -percent zinc valve and bolting, located in a valve pit that is submerged during normal operation, that will be inspected twice every 10 years, (b) there are four 24
| |
| -in. submerged lines approximately 15
| |
| -ft long in one vault and one 32
| |
| -in. submerged line approximately 10
| |
| -ft long in another pit, and (c) inspections of underground and inaccessible submerged steel piping will consist of the smaller of 2 percent of the piping length or 2 inspections every 10 years. The staff finds the applicant's response acceptable because: (a) the planned inspection quantities for underground steel piping are consistent with the recommendations provided in GALL Report AMP XI.M41, as modified by LR
| |
| -ISG-2015-01; and (b) although GALL Report AMP XI.M41 does not address inspection quantities for the inaccessible submerged environment, 2 inspections (or 2 percent of the piping length for steel) in each 10
| |
| -year period starting 10 years prior to the period of extended operation provides the staff reasonable assurance that the CLB function(s) of inaccessible submerged in
| |
| -scope components will be maintained throughout the period of extended operation. The staff's concern described in RAI B.2.1.22
| |
| -1, Part 3, is resolved.
| |
| The staff reviewed the "parameters monitored or inspected" program element and noted that it was unclear if steel components will be managed for loss of material and cracking, or loss of material, due to conflicting wording in the LRA. By letter dated November 14, 2016, the staff issued RAI B.2.1.22
| |
| -1, Part 2, requesting that the applicant state if steel components will be managed for loss of material and cracking, or loss of material, and revise the LRA as appropriate. In its response dated November 23, 2016, the applicant revised the LRA to clarify that steel components will be managed for loss of material and cracking.
| |
| The staff finds the applicant's response acceptable because managing steel components for loss of material and cracking is consistent with the recommendations provided in GALL Report AMP XI.M41, as modified by LR
| |
| -ISG-2015-01. The staff's concern described in RAI B.2.1.22
| |
| -1, Part 2, is resolved.
| |
| The staff reviewed the "detection of aging effects" program element and noted that it was unclear if two or three sets of soil samples will be obtained in each soil environment in the vicinity in which in
| |
| -scope components are buried, due to conflicting wording in the LRA. By letter dated November 14, 2016, the staff issued RAI B.2.1.22
| |
| -1, Part 1, requesting that the applicant reconcile the apparent discrepancy between the quantities of soil samples that will be obtained in each soil environment in the vicinity in which in
| |
| -scope components are buried.
| |
| In its response dated November 23, 2016, the applicant revised the LRA to clarify that soil samples will be taken at a minimum of three locations in the vicinity in which in
| |
| -scope components are buried.
| |
| | |
| Aging Management Review Results 3-195 The staff finds the applicant's response acceptable because obtaining a minimum of three sets of soil samples in the vicinity in which in
| |
| -scope components are buried is consistent with the recommendations provided in GALL Report AMP XI.M41, as modified by LR
| |
| -ISG-2015-01. The staff's concern described in RAI B.2.1.22-1, Part 1, is resolved.
| |
| The "detection of aging effects" program element in GALL Report AMP XI.M41 states that Inspection Category D may be used for those portions of in
| |
| -scope buried piping where it has been demonstrated, in accordance with the "preventive actions" program element of this AMP, that external corrosion control is not required. However, during its review, the staff found that, while the applicant's Buried Piping and Tanks Inspection Program describes soil conditions, it is unclear to the staff how Inspection Category D is applicable given that other key parameters are not described (e.g., pipe to soil potential measurements) to demonstrate external corrosion control is not required for those portions of in
| |
| -scope buried piping claiming to meet Inspection Category D. By letter dated November 14, 2016, the staff issued RAI B.2.1.22
| |
| -3, requesting that the applicant state the basis for how Inspection Category D is applicable for those portions of in-scope buried piping where the applicant claims that external corrosion control is not required.
| |
| In its response dated November 23, 2016, the applicant stated that Seabrook will not be utilizing Inspection Category D and revised LRA Section B.2.1.22 Tables 2 and 3 to state that Inspection Category D will not be used. The staff's concern described in RAI B.2.1.22
| |
| -3 is resolved.
| |
| The "acceptance criteria" program element in GALL Report AMP XI.M41, as modified by LR
| |
| -ISG-2015-01, states that acceptance criteria associated with this AMP are that cracking is absent in rigid polymeric components and that changes in jockey pump activity that cannot be attributed to leakage are not occurring. However, during its review, the staff found that the applicant's Buried Piping and Tanks Inspection Program states that cracking or blistering of polymer piping and unexplained changes in jockey pump activity are evaluated under the corrective action program. By letter dated November 14, 2016, the staff issued RAI B.2.1.22
| |
| -2, requesting that the applicant state the basis for why cracking of polymer piping and unexplained changes in jockey pump activity are evaluated under the corrective action program in lieu of being not acceptable as recommended in GALL Report AMP XI.M41, as modified by LR
| |
| -ISG-2015-01. In its response dated November 23, 2016, the applicant revised the "acceptance criteria" program element to state that cracking is absent in rigid polymeric components and changes in jockey pump activity that cannot be attributed to leakage are not occurring.
| |
| The staff finds the applicant's response acceptable because cracking of polymer piping and unexplained changes in jockey pump activity being not acceptable is consistent with the recommendations provided in GALL Report AMP XI.M41, as modified by LR
| |
| -ISG-2015-01. The staff's concern described in RAI B.2.1.22
| |
| -2 is resolved.
| |
| The "acceptance criteria" program element in GALL Report AMP XI.M41, as modified by LR
| |
| -ISG-2015-01, states that when electrical resistance corrosion rate probes will be used, the application identifies: (1) the qualifications of the individuals that will determine the installation locations of the probes and the methods of use (e.g., National Association of Corrosion Engineers (NACE) CP4, "Cathodic Protection Specialist"), and (2) how the impact of significant site features (e.g., large cathodic protection current collectors, shielding due to large objects located in the vicinity of the protected piping) and local soil conditions will be factored into Aging Management Review Results 3-196 placement of the probes and use of probe data. However, during its review, the staff found that, while the applicant's Buried Piping and Tanks Inspection Program does identify how local soil conditions will be factored into placement of the probes and use of probe data, it did not address: (1) the qualifications of the individuals that will determine the installation locations of the probes and the methods of use, and (2) how the impact of significant site features will be factored into the placement of the probes and use of probe data. By letter dated November 14, 2016, the staff issued RAI B.2.1.22
| |
| -4, requesting that the applicant provide additional information to address the two issues noted above regarding the use of electrical resistance corrosion rate probes.
| |
| In its response dated November 23, 2016, the applicant stated that Seabrook plans to utilize the -850 mV criterion for steel piping in lieu of electrical resistance corrosion rate probes and revised the "acceptance criteria" program element to remove discussion on alternatives to the
| |
| -850 mV criterion. The staff's concern described in RAI B.2.1.22
| |
| -4 is resolved.
| |
| Based on its review of letter dated October 7, 2016, and review of the applicant's responses to RAIs B.2.1.22
| |
| -1 (Parts 1
| |
| -3), B.2.1.22
| |
| -2, B.2.1.22
| |
| -3, and B.2.1.22
| |
| -4, the staff finds that program elements 1 through 7 for which the applicant claimed consistency with the GALL Report are consistent with the corresponding program elements of GALL Report AMP XI.M41, as modified by LR-ISG-2015-01. Operating Experience. LRA Section B.2.1.22-1, as modified by letter dated October 7, 2016, summarizes operating experience related to the Buried Piping and Tanks Inspection program. The applicant stated that there are no plant
| |
| -specific instances of failure of buried piping leading to loss of function of an in
| |
| -scope component. The applicant also stated that it has conducted extensive visual inspections of the interior surfaces of buried service water piping and noted no staining of the cement liner; thus, it expects that there has been no penetration of the pipe wall. The applicant further stated that an opportunistic inspection of steel fire protection piping showed no degradation of the coatings. The applicant cited two instances where wrappings or coatings were damaged including buried fuel supply piping that leaked as a result of damaged wrapping where further damage was subsequently discovered and the pipe was not returned to service and another opportunistic inspection of fire protection piping that revealed that the coating was worn but the piping was not exposed.
| |
| The staff reviewed operating experience information in the application and during the audit to determine whether the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant.
| |
| The staff did not identify any operating experience that would indicate that the applicant should consider modifying its proposed program.
| |
| Based on its review of the application, the staff finds that the applicant has appropriately evaluated plant
| |
| -specific and industry operating experience. In addition, the staff finds that the conditions and operating experience at the plant are bounded by those for which GALL Report AMP XI.M41, as modified by LR
| |
| -ISG-2015-01, was evaluated.
| |
| UFSAR Supplement. LRA Section A.2.1.22, as modified by letter dated October 7, 2016, provides the UFSAR supplement for the Buried Piping and Tanks Inspection Program. The staff reviewed this UFSAR supplement description of the program against the recommended description for this type of program as described in SRP
| |
| -LR Table 3.0
| |
| -1 and as modified by LR
| |
| -ISG-2015-01, and noted that aspects of the UFSAR summary description issued in LR
| |
| -ISG-2015-01 were not included in the revised LRA Section A.2.1.22 (e.g., annual cathodic protection Aging Management Review Results 3-197 surveys are conducted). The licensing basis for this program for the period of extended operation may not be adequate if the applicant does not incorporate this information in its UFSAR supplement. By letter dated November 14, 2016, the staff issued RAI A.2.1.22
| |
| -1, requesting that the applicant state the basis for not including aspects of the UFSAR summary description issued in LR
| |
| -ISG-2015-01 in the revised LRA Section A.2.1.22.
| |
| In its response dated November 23, 2016, the applicant revised LRA Section A.2.1.22 to incorporate aspects of the UFSAR summary description issued in LR
| |
| -ISG-2015-01 that were not included in the October 7, 2016, submittal.
| |
| The staff finds the applicant's response acceptable because the UFSAR supplement for the Buried Piping and Tanks Inspection Program, as amended by letter dated November 23, 2016, is consistent with the corresponding program description in SRP
| |
| -LR Table 3.0
| |
| -1, as modified by LR-ISG-2015-01. The staff's concern described in RAI A.2.1.22
| |
| -1 is resolved.
| |
| The staff also noted that, by letter dated November 23, 2016, the applicant committed to implementing the new Buried Piping and Tanks Inspection Program within 10 years prior to the period of extended operation for managing the effects of aging for applicable components.
| |
| The staff finds that the information in the UFSAR supplement, as amended by letter dated November 23, 2016, is an adequate summary description of the program.
| |
| Conclusion. On the basis of its audit and review of the applicant's Buried Piping and Tanks Inspection Program, the staff concludes that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.3.2 345 kV SF 6 Bus Program Summary of Technical Information in the Application. LRA Section B.2.2.1 describes the new 345 kV SF 6 Bus Program as a plant
| |
| -specific program. The applicant states that this program will manage the following aging effects on the 345 kV SF 6 Bus:
| |
| * loss of pressure boundary due to elastomer degradation
| |
| * loss of material due to pitting, crevice, and galvanic corrosion
| |
| * loss of function due to unacceptable air, moisture, or sulfur dioxide (SO
| |
| : 2) levels Sulfur hexafluoride (SF
| |
| : 6) is an inert gas used to insulate the bus conductor. The program will inspect for corrosion on the exterior of the bus duct housing, test for leaks at elastomers, and periodically test SF 6 gas samples to determine air, moisture, and SO 2 levels. The presence of air or moisture may lead to the loss of intended function. SO 2 levels are an indication of partial discharge internal to the bus ducts. Staff Evaluation. The staff reviewed the program elements one through six of the applicant's program against the acceptance criteria for the corresponding elements as stated in SRP
| |
| -LP Section A.1.2.2. The staff's review focused on how the applicant's program manages aging Aging Management Review Results 3-198 effects through the effective incorporation of these program elements. The staff's evaluation of each of these elements follows.
| |
| Scope of the Program. LRA Section B.2.2.1 states the 345 kV SF 6 Bus Program is credited for maintaining the pressure boundary formed by the exterior metal housing and elastomers. The program also monitors critical SF 6 parameters such as air, moisture, and SO 2 levels. The SF 6 Bus Program will routinely monitor the integrity of the elastomers by performing leak tests.
| |
| The 345 kV SF 6 Bus AMP in
| |
| -scope bus segments are those bus segments included in the recovery path for an SBO event. Two possible recovery paths are identified as follows:
| |
| * The first path includes the SF 6 bus from 345 kV Power Circuit Breakers 11 and 12 to the generator step
| |
| -up transformer and to the unit auxiliary transformers via the isolated phase bus.
| |
| * The second path includes the SF 6 bus from 345 kV Power Circuit Breakers 52 and 695 to the reserve auxiliary transformers.
| |
| The staff reviewed the applicant's "scope of program" program element against the criteria in SRP-LR Section A.1.2.3.1, which states that the scope of program should include the specific structures and components of which the program manages the aging.
| |
| The specific commodity groups for which the program manages aging effects are identified as the two paths above, which satisfies the criterion defined in SRP
| |
| -LR Appendix A.1.2.3.1.
| |
| The staff confirmed that the "scope of the program" program element satisfies the criterion defined in SRP
| |
| -LR Section A.1.2.3.1; therefore, the staff finds it acceptable.
| |
| Preventive Actions. LRA Section B.2.2.1 states that actions of the 345 kV SF 6 Bus Program is to perform tests and inspections. The applicant stated that tests and inspections shall be performed prior to entering the period of extended of operation and at least once every 6 months thereafter. No preventive actions are taken as part of this program to prevent or mitigate aging degradation.
| |
| The "preventive actions" program element criterion in SRP
| |
| -LR Section A.1.2.3.2 is that Condition Monitoring Programs do not rely on preventive actions; thus, preventive actions need not be provided. The staff determined that the preventive actions program element satisfies th e criterion defined in SRP
| |
| -LR Section A.1.2.3.2. The staff finds it acceptable because this is a Condition Monitoring Program, and there is no need for preventive actions. The staff finds this program element acceptable.
| |
| The staff confirms that the "preventive actions" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.2; therefore, the staff finds it acceptable.
| |
| Parameters Monitored or Inspected. LRA Section B.2.2.1 states that the 345 kV SF 6 Bus Program performs tests and inspections to maintain the critical parameters of the SF 6 bus system prior to entering the period of extended of operation and at least once every 6 months thereafter. Critical parameters of the SF 6 bus system are mechanical integrity of the system to maintain a pressure boundary and maintenance of acceptable air, moisture, and SO 2 levels. The applicant stated that the program includes pressure monitoring of the SF 6 gas to ensure Aging Management Review Results 3-199 that adequate insulating properties are maintained. The applicant also stated that the program performs periodic tests on samples of the SF 6 gas to determine air, moisture, and SO 2 levels as well as inspections for loss of materials on the exterior surfaces of the duct.
| |
| The staff reviewed the applicant's "parameters monitored or inspected" program element against the criteria in SRP
| |
| -LR Section A.1.2.3.3, which states the parameters to be monitored or inspected should be identified and linked to the degradation of the particular structure and component intended function(s). Additionally, for a Condition Monitoring Program, the parameters monitored or inspected should detect the presence and extent of aging effects.
| |
| The parameters monitored or inspected will provide evidence of degradation of the insulating properties of the SF 6 gas via sample testing. Also, the pressure monitoring of the SF 6 gas and detection of loss of materials on the SF 6 bus duct system will help to maintain its pressure boundary and ensure the component intended function during the period of extended operation.
| |
| The staff confirmed that the "parameters monitored or inspected" program element satisfies the criterion defined in SRP
| |
| -LR Section A.1.2.3.3 of the SRP
| |
| -LR; therefore, the staff finds it acceptable.
| |
| Detection of Aging Effects. LRA Section B.2.2.1 states that the 345 kV SF 6 Bus Program tests samples of the SF 6 gas to determine if the insulating properties are adequate. These tests are focused on air, moisture, and SO 2 levels. The SO 2 measurements provide an indication of arcing internal to the bus. The gas is sampled, and its properties are tested prior to entering the period of extended operation and at least once every 6 months thereafter.
| |
| The applicant stated that the program maintains the pressure boundary by monitoring the pressure of SF 6 gas and inspecting for leaks. The system SF 6 bus will be inspected for leaks prior to entering the period of extended operation and at least once every 6 months thereafter.
| |
| The applicant also stated that the program performs visual inspections on the exterior surfaces of the duct prior to entering the period of extended operation and at least once every 6 months thereafter.
| |
| The staff reviewed the applicant's "detection of aging effects" program element against the criteria in SRP
| |
| -LR Section A.1.2.3.4, which states that the parameters to be monitored or inspected should be appropriate to ensure that the structures and components intended function(s) will be adequately maintained for license renewal under all CLB design conditions. This includes aspects such as method or technique (e.g., testing samples of SF 6 gas, visual inspection for surface of duct), frequency, and timing of inspection to ensure timely detection of aging effects.
| |
| Testing samples of SF 6 gas for insulating properties and visual inspection of the bus duct are an acceptable method to detect a degradation of SF 6 bus systems. The staff also determined that periodic tests on samples and visual inspection every 6 months are adequate to detect the degradation of insulating properties.
| |
| The staff confirmed that the "detection of aging effects" program element satisfies the criterion defined in SRP
| |
| -LR Section A.1.2.3.4; therefore, the staff finds it acceptable.
| |
| | |
| Aging Management Review Results 3-200 Monitoring and Trending. LRA Section B.2.2.1 states that the 345 kV SF 6 Bus Program includes trending actions of the SF 6 properties. The applicant stated that trending provides additional data, which can be analyzed to determine the rate of change in the measured parameters against the acceptance criteria. The applicant further stated that analysis of the collected data against the acceptance criteria and inspection may result in corrective actions.
| |
| The staff reviewed the applicant's "monitoring and trending" program element against the criteria in SRP
| |
| -LR Section A.1.2.3.5, which states that monitoring and trending activities should be described, and they should provide predictability of the extent of degradation and thus affect timely corrective or mitigative actions. This program element describes how the data collected are evaluated and may also include trending for a forward look.
| |
| The staff determined that once every 6 months testing and visual inspection for monitoring and trending and activities is acceptable since testing and inspection provide a prediction regarding the rate of degradation in order to confirm that timing of the next scheduled inspection and testing will occur before a loss of the structure and component intended function.
| |
| The staff confirmed that the "monitoring and trending" program element satisfies the criterion defined in the SRP
| |
| -LR Section A.1.2.3.5; therefore, the staff finds it acceptable.
| |
| Acceptance Criteria. LRA Section B.2.2.1 states that the 345 kV SF 6 Bus Program performs leak tests, tests the quality of SF 6 gas, and inspects for loss of material. The applicant described the following criteria as acceptance criteria:
| |
| The Seabrook program maintains the pressure boundary by inspecting for leaks and monitoring SF 6 gas pressure. The minimum acceptable pressure value is sufficient to provide adequate insulation between the conductor and the exterior housing. The SO 2 measurements of the SF 6 gas provide an indication of partial discharge occurring internal to the bus. Any indication of the presence of SO 2 will be evaluated by engineering staff. The evaluation will provide corrective action required.
| |
| A dew point check is used to determine the moisture content of the SF 6 gas. The maximum allowable dew point measurement is below the dew point value that would lead to break
| |
| -down of the insulation.
| |
| Purity check is used to determine the air content of the SF 6 gas. The maximum allowable air content is below the value that would lead to breakdown of the insulation.
| |
| Visual inspection on the exterior surfaces of the duct will detect the presence of pitting, crevice, and galvanic corrosion. Engineering evaluations will be performed if corrosion is found on the duct. The evaluation will determine the ability of the remaining wall thickness to maintain the required pressure boundary.
| |
| The staff reviewed the applicant's "acceptance criteria" program element against the criteria in SRP-LR Section A.1.2.3.6, which states that the acceptance criteria of the program and their bases should be described. The acceptance criteria, against which the need for corrective actions will be evaluated, should ensure that the structure and component intended function(s) are maintained under all CLB design conditions during the period of extended operation.
| |
| | |
| Aging Management Review Results 3-201 The acceptance criteria for the tests and inspection provide assurance that the SF 6 gas maintains its intended function as the bus insulation under CLB design conditions.
| |
| The staff determined that the "acceptance criteria" program element satisfies the criteria defined in SRP-LR Section A.1.2.3.6; therefore, the staff finds it acceptable. Operating Experience. LRA Section B.2.2.1 summarizes operating experiences related to the 345 kV SF 6 Bus Program. The applicant stated that Seabrook routinely performs monitoring and test activities for various parameters of the SF 6 bus. The inspections and tests are performed as part of maintenance activities. Results that are not acceptable are documented in the corrective action program.
| |
| The applicant stated that the program relied on a review of the corrective action program database to provide the basis of this review. The applicant also stated that its review of the recent operating experience for the SF 6 leak inspections at Seabrook increased the reliability of the SF 6 switchyard. Also, in 2008, the applicant experienced an increase in the level of SO 2 in a sample of the SF 6 gas. An engineering evaluation attributed the increase to thermal cycling or partial discharge, which occurs with normal switch operation. The SF 6 gas was filtered. This operating experience demonstrates the ability of Seabrook to routinely detect and analyze anomalies prior to loss of intended function. Plant
| |
| -specific and industry operating experiences will be evaluated in the development and implementation of this program. As additional operating experience is obtained, the applicant will incorporate lessons learned into the program. The staff reviewed this information against the acceptance criteria in SRP
| |
| -LR Section A.1.2.3.10, which states that operating experience with existing programs shoul d be discussed. The operating experience should provide objective evidence to support the conclusion that the effects of aging will be adequately managed so that the structure and component intended function(s) will be maintained during the period of extended operation.
| |
| During its review, the staff found no operating experience to indicate that the applicant's program would not be effective in adequately managing aging effects during the period of extended operation.
| |
| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that the program can adequately manage the detrimental effects of aging on SSCs within the scope of the program and implementation of the program has resulted in the applicant taking corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.2.1 provides the UFSAR supplement for the 345 kV SF 6 Bus Program. The staff reviewed the UFSAR supplement description of the program and noted that it conforms to the recommendation for this type of program, as described in SRP
| |
| -LR Section 3.6.3.4 and Table 3.6
| |
| -2. The staff also noted that the applicant committed (Commitment 40) to implementing the 345 kV SF 6 Bus Program prior to the period of extended operation for managing aging of applicable components.
| |
| | |
| Aging Management Review Results 3-202 The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its technical review of the applicant's 345 kV SF 6 Bus Program, the staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.3.3 Boral Monitoring Program Summary of Technical Information in the Application. LRA Section B.2.2.2 describes the existing Boral Monitoring Program as plant
| |
| -specific. The applicant stated that the program manages the aging effects of reduction of neutron absorbing capacity due to Boral degradation.
| |
| It also manages changes in the dimensions and loss of material due to general corrosion of Boral neutron absorbing material in the spent fuel pool racks by relying on representative coupon samples mounted in a coupon "train" located in the spent fuel pool to monitor performance of the absorber material without disrupting the integrity of the storage system. The applicant further stated that the program ensures the Boral neutron absorbers in the spent fuel racks maintain the validity of the criticality analysis in support of the rack design.
| |
| Staff Evaluation. The staff reviewed program elements one through six of the applicant's program against the acceptance criteria for the corresponding elements as stated in SRP
| |
| -LR Section A.1.2.3. The staff's review focused on how the applicant's program manages aging effects through the effective incorporation of these program elements. The staff's evaluation of each of these elements follows.
| |
| Scope of the Program. LRA Section B.2.2.2 states that the applicant's spent fuel pool is divided into two regions. The applicant further stated that region one has six racks with Boral as the neutron absorber that allow space for 576 fuel assemblies. The applicant further stated that region two contains Boraflex as the neutron absorber and is not credited in the criticality analysis; therefore, region two is not within the scope of license renewal. The applicant also stated that the scope of the program is the management of the reduction of neutron
| |
| -absorbing capacity of the Boral sheets in region one. The applicant stated that this is accomplished by monitoring neutro n-absorbing capacity, inspecting for changes in dimensions and inspecting for loss of material due to general corrosion caused by the effects of the spent fuel pool environment on representative Boral coupons.
| |
| The staff reviewed the applicant's "scope of program" program element against the criteria in SRP-LR Section A.1.2.3.1, which states that the scope of the program should include the specific structures and components of which the program manages the aging, and it finds that the applicant adequately described the structures and components to be managed.
| |
| The staff confirmed that the "scope of the program" program element satisfies the criterion defined in SRP
| |
| -LR Section A.1.2.3.1; therefore, the staff finds it acceptable.
| |
| Preventive Actions. LRA Section B.2.2.2 states that the applicant's Boral Monitoring Program is a Condition Monitoring and Inspection Program; therefore, there are no preventive actions required.
| |
| | |
| Aging Management Review Results 3-203 The staff reviewed the applicant's "preventive actions" program element against the criteria in SRP-LR Section A.1.2.3.2, which states that for Condition or Performance Monitoring Programs, they do not rely on preventive actions; thus, this information need not be provided.
| |
| The staff confirmed that the "preventive actions" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.2; therefore, the staff finds it acceptable.
| |
| Parameters Monitored or Inspected. LRA Section B.2.2.2 states that the applicant uses standard Boral coupons of the same design as, and traceable to, the specific Boral heat lot material used in the fabrication of the spent fuel racks. The applicant stated that the standard coupons are placed in the spent fuel pool for monitoring of the aging effects and control coupons were supplied, in addition to standard coupons, to benchmark coupon initial conditions, to monitor possible uncontrolled changes in Boral material that are unrelated to the spent fuel pool conditions, and to demonstrate comparisons between different examination techniques and service contractors. The applicant further stated that the program monitors changes in the physical properties of the Boral coupons such as blistering, pitting, cracks, corrosion and spalling, loss of material, and other damage or condition. The applicant also stated that the physical dimensional requirements of the coupons are also monitored, and two or more Boral coupons are selected each RFO for examination by an outside contractor where neutron attenuation, neutron radiography examination, and other nondestructive examinations are performed.
| |
| The staff reviewed the applicant's "parameters monitored or inspected" program element against the criteria in SRP
| |
| -LR Section A.1.2.3.3, which states that the parameters to be monitored or inspected should be identified and linked to the degradation of the particular structure and component intended function(s). The SRP
| |
| -LR also states that, for a Performance Monitoring Program, a link should be established between the degradation of the particular structure or component intended function(s) and the parameter(s) being monitored.
| |
| After reviewing the "parameters monitored or inspected" program element, the staff determined that the applicant adequately addressed the criterion defined in SRP-LR Section A.1.2.3.3.
| |
| Inspection of the Boral coupons, which are indicative of the Boral in the spent fuel pool, is an acceptable means to monitor for the aging effects of loss of material and reduction of neutron absorber capacity. Furthermore, monitoring the physical condition of the neutron
| |
| -absorbing material, such as geometric changes in the material (formation of blisters, pits and bulges), and decreased boron areal density makes this element of the program consistent with LR-ISG-2009-01, "Aging Management of Spent Fuel Pool Neutron
| |
| -Absorbing Materials other than Boraflex."
| |
| The staff confirmed that the "parameters monitored or inspected" program element satisfies the criterion defined in SRP
| |
| -LR Section A.1.2.3.3; therefore, the staff finds it acceptable.
| |
| Detection of Aging Effects. LRA Section B.2.2.2 states the Boral Monitoring Program monitors coupon samples located in the spent fuel pool to determine the condition of the neutron absorber material without disrupting the integrity of the spent fuel storage system. The applicant stated that the program measures certain physical and chemical properties of these sample coupons each RFO. The applicant further stated that the program maintains the coupon train within the spent fuel pool positioned such that the coupons experience the same conditions as the Boral panels built into the actual fuel racks. The applicant further stated that Aging Management Review Results 3-204 the coupons are mounted in stainless steel jackets and stainless steel coupon train mimicking the construction of the fuel racks designed to recreate the spent fuel pool environment for known effects and potential effects that may be unknown at this time The staff reviewed the applicant's "detection of aging effects" program element against the criteria in SRP
| |
| -LR Section A.1.2.3.4, which states that detection of aging effects should occur before there is loss of the structure and component intended function(s). The parameters to be monitored or inspected should be appropriate to ensure that the structure and component intended function(s) will be adequately maintained for license renewal under all CLB design conditions. This includes aspects such as method or technique (e.g., visual, volumetric, surface inspection), frequency, sample size, data collection, and timing of new and one
| |
| -time inspections to ensure timely detection of aging effects. Additionally the program should provide information that links the parameters to be monitored or inspected to the aging effects being managed.
| |
| After reviewing the "detection of aging effects" program element, the staff determined that the applicant adequately addressed the criterion defined in SRP
| |
| -LR Section A.1.2.3.4 because the Boral Monitoring Program is set up to facilitate early detection of aging effects in the Boral sheets in the spent fuel pool via detection of aging effects in the Boral coupons. The Boral Monitoring Program tests selected coupons every RFO, exposes the coupons to a similar environment to that of the actual Boral in the spent fuel pool, and maximizes the amount of exposure the coupon trains receive while in the spent fuel pool.
| |
| The staff confirmed that the "detection of aging effects" program element satisfies the criterion defined in SRP
| |
| -LR Section A.1.2.3.4; therefore, the staff finds it acceptable. Monitoring and Trending. LRA Section B.2.2.2 states that the neutron attenuation tests are trended to ensure that degradation does not challenge the assumptions within the spent fuel pool criticality analysis of record. The applicant stated that observable loss in neutron attenuation ability, if any, is projected to determine when neutron attenuation may fall below acceptance criteria. Additionally, the applicant stated that, along with size and weight measurements to determine the extent of shrinkage or loss of material, blister shape and size are recorded and trended to determine whether new blisters are forming, the rate of growth of existing blisters, and the rate of increase in blister thickness.
| |
| The staff reviewed the applicant's "monitoring and trending program" program element against the criteria in SRP
| |
| -LR Section A.1.2.3.5, which states that monitoring and trending activities should be described, and they should provide predictability of the extent of degradation and thus effect timely corrective or mitigative actions. Plant
| |
| -specific or industry
| |
| -wide operating experience or both may be considered in evaluating the appropriateness of the technique and frequency.
| |
| After reviewing the "monitoring and trending" program element, the staff determined that the applicant adequately addressed the criterion defined in SRP
| |
| -LR Section A.1.2.3.5 because the applicant's Boral Monitoring Program includes trending of the degradation of the boral coupons as well as the physical characteristics of the coupons, which is congruent with the recommendations, as described in SRP
| |
| -LR Section A.1.2.3.5.
| |
| The staff confirmed that the "monitoring and trending" program element satisfies the criterion defined in SRP
| |
| -LR Section A.1.2.3.5; therefore, the staff finds it acceptable.
| |
| | |
| Aging Management Review Results 3-205 Acceptance Criteria. LRA Section B.2.2.2 states that the purpose of the applicant's Boral Monitoring Program is to ensure that degradation does not challenge the design bases and assumptions within the spent fuel pool criticality analysis of record. The applicant further stated that the design of the region one spent fuel racks containing Boral as a neutron absorbing material assures a Keff less than 0.95 (5
| |
| -percent subcriticality margin). The applicant stated that the acceptance criteria for the following properties are applied to each exposed standard Boral coupon inspected.
| |
| The applicant stated that failure to meet acceptance criteria is addressed by the following engineering evaluation:
| |
| (1) Voided Blister Displacement
| |
| -the total blister void volume for all blisters present on both sides of a coupon will be less than a 45 mil uniform void over the area of the coupon. The rate of change in blister displacement provides indication of availability of sufficient margin to avoid exceeding the 45 mil uniform void prior to the next Boral coupon examination.
| |
| (2) Boron Carbide Loss
| |
| -B10 areal density measured by thermal neutron attenuation will be greater than 0.02 gm/cm 2 [grams per square centimeter] as specified within the criticality analysis and material specification. The rate of change in boron carbide loss provides indication of availability of sufficient margin to maintain the 0.02 gm/cm 2 B 10 areal density beyond the next Boral coupon examination.
| |
| (3) Boron Carbide Redistribution
| |
| -Boron carbide distribution will be uniform as observed by thermal neutron radiography. Thinned or depleted areas will satisfy the criterion for boron carbide loss discussed above.
| |
| The staff reviewed the applicant's "acceptance criteria" program element against the criteria in SRP-LR Section A.1.2.3.6, which states that the acceptance criteria of the program and its basis should be described. The acceptance criteria, against which the need for corrective actions will be evaluated, should ensure that the structure and component intended function(s) are maintained under all CLB design conditions during the period of extended operation. The program should include a methodology for analyzing the results against applicable acceptance criteria.
| |
| After reviewing the "acceptance criteria" program element, the staff determined that the applicant adequately addressed the criterion defined in SRP
| |
| -LR Section A.1.2.3.6 because the acceptance criterion listed in the applicant's Boral Monitoring Program are congruent with the recommendations of SRP
| |
| -LR A.1.2.3.6. These acceptance criterion will ensure that the structure and component intended function(s) are maintained under all CLB design conditions during the period of extended operation.
| |
| The staff confirmed that the "acceptance criteria" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.6; therefore, the staff finds it acceptable.
| |
| Operating Experience. LRA Section B.2.2.2 summarizes operating experience related to the Boral Monitoring Program. The applicant stated that the Boral Monitoring Program is an existing AMP proposed for the period of extended operation.
| |
| The applicant stated that the operating experience included the following:
| |
| | |
| Aging Management Review Results 3-206 (1) During planned work involving an inspection of the Spent Fuel Pool Boral coupon tree in 2003, an unexpected blistering of the Boral material was identified when one of the Boral coupons was examined.
| |
| : a. The condition report evaluation concluded that the effect on the current Spent Fue l Pool criticality analysis was insignificant and the current blistered condition was acceptable as is. The evaluation stated that the degree of Boral blistering was expected to increase with repeated exposure to gamma energies present during offload; as such, a Boral monitoring program was established to evaluate future changes in the Boral material. Since the Boral monitoring program would not gather any additional data on the blistering events until after the next core offload, a water reduction in the flux trap equal to 90mils was analyzed and applied to the revised criticality analyses to formally accommodate any increased blistering at offload.
| |
| : b. The revised type determination curves are conservative to the existing curves at all points, and were implemented prior to core offload. The type determination curves with the 90 mil allowance were included to accommodate any future blistering. This allowance is used as an acceptance criterion for the Boral monitoring program. Other acceptance criteria will include the Boron10 areal density.
| |
| (2) As of January 2003, a Boral Monitoring Program had not yet been formally established following implementation of the engineering change to incorporate Boral instead of Boraflex in the second set of fuel racks. Although no commitment had been made to implement such a program, Seabrook Station opted to establish a Boral coupon monitoring program as a good practice.
| |
| (3) During the Cycle 10 monitoring program (Spring of 2005), aluminum cladding oxidation and spalling was observed on Boral coupons. Photos of these coupons taken in the previous monitoring cycle were reviewed and showed oxidation but no evidence of spalling. The progression and effect of this oxidation and spalling was evaluated and predicted to remain within the program acceptance criteria through the next coupon examination in Cycle 11, when the material would be re
| |
| -evaluated.
| |
| The Boral oxidation and spalling condition was described and posted with [Institute of Nuclear Plant Operation] INPO as operating experience on August 26, 2005.
| |
| The Cycle 11 examinations (Fall of 2006) indicated continued aluminum cladding oxidation on most coupons. The potential degradation of neutron absorbing capacity due to continued, and eventually through
| |
| -wall, oxidation and spalling was evaluated by observing previously dissected blisters on special coupon A131. Blisters on this coupon had been intentionally dissected to investigate the effect on the Boral should a blistered area break through. By dissecting the blisters, the cermet [ceramic
| |
| -metallic] compound was now exposed directly to the Spent Fuel Pool water. The altered coupon A131 with dissected blisters had been exposed to the Spent Fuel Pool conditions for approximately 3 years, and was then indicating measurable change in B10 areal density in the bare cermet. The results of the Cycle 11 examinations indicated continued aluminum cladding oxidation. The Boral coupons did, however, remain well within the areal density specification. The change in B10 areal density was just above the lower limit of Aging Management Review Results 3-207 detection by visual examination. The corrosion process appeared to be proceeding very slowly. The potential for measurable B10 loss in the unaltered coupons was reasonably expected within the next few cycles. Therefore long term B10 areal density monitoring, via neutron attenuation, was also implemented to ensure conformance to Boral specifications.
| |
| The staff reviewed this information against the acceptance criteria in SRP
| |
| -LR Section A.1.2.3.10, which states that the operating experience of AMPs, including past corrective actions resulting in program enhancements or additional programs, should be considered. A past failure would not necessarily invalidate an AMP because the feedback from operating experience should have resulted in appropriate program enhancements or new programs. This information can show where an existing program has succeeded and where it has failed (if at all) in intercepting aging degradation in a timely manner. This information should provide objective evidence to support the conclusion that the effects of aging will be adequately managed so that the structure and component intended function(s) will be maintained during the period of extended operation.
| |
| The staff reviewed neutron radiography examination data as well as the applicant's technique for determining areal density of the Boral coupons. This technique involves performing visual examinations of the radiographical images of coupons. During its review, the staff identified operating experience, which could indicate that the applicant's program may not be effective in adequately managing aging effects during the period of extended operation. The staff determined the need for additional clarification, which resulted in the issuance of an RAI.
| |
| In LRA Section B.2.2.2 the applicant stated that Boral coupons are selected each RFO for examination by an outside contractor. By letter dated December 14, 2010, the staff issued RAI B.2.2.2-1, requesting additional information on how the coupons were handled by the applicant and the contractor to ensure the condition of the coupons were representative of the coupons upon exiting the pool and not due to the handling and transportation of the coupons to the testing facility.
| |
| In its response dated January 13, 2011, the applicant provided excerpts from both the contractor procedure and its own program documents detailing the controls put in place to ensure consistent and effective handling and testing of the Boral coupons. The applicant further provided details on the different tests done on the coupons once they arrive at the contractor facility. Based on its review, the staff finds the applicant's response to RAI B.2.2.2 acceptable because the applicant demonstrated the appropriate level of care to ensure that the coupons analyzed are the most representative of the Boral in the spent fuel pool.
| |
| Based on its review of the application, and review of the applicant's responses to RAI B.2.2.2, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking appropriate corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.2.2 provides the UFSAR supplement for the Boral Monitoring Program. The staff reviewed this UFSAR supplement description of the program Aging Management Review Results 3-208 and noted that it conforms to the recommended description for this type of program, as described in LR
| |
| -ISG-2009-01. The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| Conclusion. On the basis of its technical review of the applicant's Boral Monitoring Program, the staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.3.4 Nickel-Alloy Nozzles and Penetrations Program Summary of Technical Information in the Application. LRA Section B.2.2.3 describes the existing Nickel
| |
| -Alloy Nozzles and Penetrations Program as plant
| |
| -specific. The applicant stated that the Nickel
| |
| -Alloy Nozzles and Penetrations Program manages the aging effect of cracking due to PWSCC of nickel
| |
| -based alloy pressure boundary and structural components exposed to reactor coolant.
| |
| Staff Evaluation. The staff reviewed program elements one through six and ten of th e applicant's program against the acceptance criteria for the corresponding elements, as stated in SRP-LR Section A.1.2.3. The staff's review focused on how the applicant's program manages aging effects through the effective incorporation of these program elements. The staff's evaluation of each of these elements follows.
| |
| SRP-LR Table 3.1
| |
| -1, IDs 31 and 34, and their subordinate items, are unique in the GALL Report in that they do not recommend that aging be managed through the use of an AMP contained in the SRP-LR. Rather, they recommend specific aging management activities. For nickel
| |
| -alloy materials addressed by these AMR items, the recommended aging management activities consist of the following:
| |
| * use of Inservice Inspection (IWB, IWC, and IWD) AMP
| |
| * use of Water Chemistry AMP
| |
| * compliance with all NRC Orders
| |
| * commitment to implement applicable bulletins and generic letters
| |
| * commitment to implement staff accepted industry guidelines The approach taken in the SRP
| |
| -LR for these AMR items permits license renewal applicants to demonstrate consistency with the GALL Report by citing these aging management activities in their LRA AMR items. Alternatively, as has been done in this case, consistency with the GALL Report may be demonstrated for these items by developing an AMP and citing it for each applicable AMR item, which is consistent with SRP
| |
| -LR Section A.1.2.3 and which addresses all of the recommended aging management activities listed above. The staff's review of this AMP is, therefore, designed to verify consistency with SRP
| |
| -LR Section A.1.2.3 and to ensure that the aging management activities listed for nickel
| |
| -alloy components included in SRP
| |
| -LR Table 3.1
| |
| -1, IDs 31 and 34, are addressed by the AMP.
| |
| | |
| Aging Management Review Results 3-209 Scope of the Program. LRA Section B.2.2.3 states that the Nickel
| |
| -Alloy Nozzles and Penetrations Program is an existing program that manages the effects of aging of nickel
| |
| -alloy components including alloy 82/182 weld metal in accordance with industry guidance documents, ASME B&PV Code, Code Case N
| |
| -722, and 10 CFR 50.55a. The scope of the program element contains a specific list of components, which are included within the scope as well as a general specification of components, which are excluded. This section also states that the AMP complies with applicable NRC Orders and implements applicable NRC bulletins, generic letters, and staff
| |
| -accepted industry guidelines.
| |
| The staff reviewed the applicant's "scope of the program" program element against the criteria in SRP-LR Section A.1.2.3.1, which states that the program should include the specific structures and components for which the program manages aging.
| |
| Based on the list provided, which addresses materials and components included within the scope of the AMP, the staff confirmed that the "scope of the program" program element satisfies the criterion defined in SRP
| |
| -LR Section A.1.2.3.1; therefore, the staff finds it acceptable.
| |
| Preventive Actions. LRA Section B.2.2.3 states that the Water Chemistry Program AMP is used to prevent and mitigate PWSCC. Additionally, this section of the LRA states that several other preventive and mitigative techniques are available for use. These techniques include mechanical stress improvement, induction heat stress improvement, weld overlay, mechanical nozzle seal assembly, zinc injection, abrasive water jet, nickel plating, or replacement with Alloy 690/52/152 components.
| |
| The staff reviewed the applicant's "preventive actions" program element against the criteria in SRP-LR Section A.1.2.3.2, which states that activities for prevention and mitigation programs should be described.
| |
| Based on the description of the available mitigative techniques, the staff confirmed that the "preventive actions" program element satisfies the criterion defined in SRP
| |
| -LR Section A.1.2.3.2; therefore, the staff finds it acceptable.
| |
| Parameters Monitored or Inspected. LRA Section B.2.2.3 states that the program monitors cracking due to PWSCC of Alloy 600/82/182 materials exposed to reactor coolant. This LRA section also states that the program performs condition monitoring examinations of the lower reactor vessel head surface and each bottom
| |
| -mounted instrumentation tube penetration. This LRA section additionally states that these examinations monitor for through
| |
| -wall cracks that may exist in the nozzles or their associated partial penetration J
| |
| -groove welds. This LRA section further states that, for other in
| |
| -scope pressure boundary components, the program monitors for evidence of reactor coolant leakage which may manifest itself in the form of boric acid residues or corrosion products. This LRA section finally states that the core support pads and lugs and clevis inserts are VT
| |
| -3 inspected once per interval for evidence of cracking.
| |
| The staff reviewed the applicant's "parameters monitored or inspected" program element against the criteria in SRP
| |
| -LR Section A.1.2.3.3, which states that the parameters to be monitored or inspected should be identified and linked to the degradation of the particular structure and component intended function(s). Additionally, for a Condition Monitoring Program, the parameters monitored or inspected should detect the presence and extent of aging effects.
| |
| | |
| Aging Management Review Results 3-210 The staff finds that, for the components under consideration, cracking is the degradation mechanism, which will affect their intended function and that the exams included in the program will be capable of directly detecting cracks or will be capable of detecting secondary evidence of cracks (e.g., boric acid). Based on this finding, the staff confirmed that the "parameters monitored or inspected" program element satisfies the criterion defined in SRP
| |
| -LR Section A.1.2.3.3; therefore, the staff finds it acceptable.
| |
| Detection of Aging Effects. LRA Section B.2.2.3 states that visual, surface, and volumetric exams are used to detect cracking due to SCC in Alloy 600/82/182 components. In this element, the applicant also states that SSCs will be inspected in accordance with the ASME Code, Section XI, Subsections IWB, IWC, and IWD Program.
| |
| The staff reviewed the applicant's "detection of aging effects" program element against the criteria in SRP
| |
| -LR Section A.1.2.3.4, which states that detection of aging effects should occur before there is a loss of the structure and component intended function(s). The criteria also states that parameters to be monitored or inspected should be appropriate to ensure that the structure and component intended function will be adequately maintained for license renewal under all CLB design conditions. The criteria further states that a program based solely on detecting structure and component failure should not be considered as an effective AMP for license renewal. The criteria states that this program element describes "when," "where," and "how" program data are collected (i.e., all aspects of activities to collect data as part of the program). The criteria continue by stating that the method or technique and frequency may be linked to plant
| |
| -specific or industry
| |
| -wide operating experience.
| |
| In its review, the staff determined that cracking is an appropriate parameter to monitor to ensure the maintenance of intended function of the components under consideration. The staff also determined that a combination of visual, surface, and volumetric test methods were capable of detecting cracking or secondary evidence of cracking (e.g., boric acid, prior to loss of intended function). The staff additionally determined that this AMP refers to the Code of Federal Regulations, the ASME Code, and various code cases and that the specifications (how, where, when) for these inspections are contained in these documents. The staff finally determined that there is no industry
| |
| - or plant-specific operating experience, which necessitates deviating from the inspections proposed in this program element.
| |
| Based on the above evaluation, the staff confirmed that the "detection of aging effects" program element satisfies the criterion defined in SRP
| |
| -LR Section A.1.2.3.4; therefore, the staff finds it acceptable.
| |
| Monitoring and Trending. LRA Section B.2.2.3 states that the program incorporates the inspection schedules and frequencies for the nickel
| |
| -alloy components in accordance with the ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program and, where applicable, ASME Code Case N
| |
| -722, subject to the conditions specified in 10 CFR 50.55a(g)(6)(ii)(E). This section also provides a list of inspections to be conducted including the frequency of those inspections.
| |
| The staff reviewed the applicant's "monitoring and trending" program element against the criteria in SRP
| |
| -LR Section A.1.2.3.5, which states that monitoring and trending activities should be described, and they should provide predictability of the extent of degradation and, thus, effect timely corrective or mitigative actions. The criteria also states that plant
| |
| -specific or Aging Management Review Results 3-211 industry-wide operating experience or both may be considered in evaluating the appropriateness of the technique and frequency. The criteria further states that this program element describes "how" the data collected are evaluated and may also include trending for a forward look, including an evaluation of the results against the acceptance criteria and a prediction regarding the rate of degradation in order to confirm that timing of the next scheduled inspection will occur before a loss of SC intended function.
| |
| In this review, the staff determined that this program element adequately describes the monitoring and trending that is proposed. The staff also determined that the governing documents for the inspections to be monitored and trended provide sufficient guidance concerning inspection frequency and the modification of that frequency based on past inspections, or other plant-specific or industry operating experience, to provide timely corrective action or mitigation or additional inspections prior to loss of intended function. The staff further determined that the program element and the governing documents provided sufficient guidance to allow collected data to be compared to applicable acceptance standards.
| |
| Based on the above evaluation, the staff confirmed that the "monitoring and trending" program element satisfies the criterion defined in SRP
| |
| -LR Section A.1.2.3.5; therefore, the staff finds it acceptable.
| |
| Acceptance Criteria. LRA Section B.2.2.3 states that acceptance criteria for this program are contained in governing documents (e.g., ASME Code and Code Cases).
| |
| The staff reviewed the applicant's "acceptance criteria" program element against the criteria in SRP-LR Section A.1.2.3.6, which states the acceptance criteria of the program and its basis should be described to include ensuring that the structure and component intended function(s) are maintained under all CLB design conditions during the period of extended operation.
| |
| Acceptance criteria could be specific numerical values, or could consist of a discussion of the process for calculating specific numerical values of conditional acceptance criteria to ensur e that the structure and component intended function(s) will be maintained under all CLB design conditions. Information from available references may be cited. The criteria also states that acceptance criteria, which do permit degradation, are based on maintaining the intended function under all CLB design loads. The criteria further states that qualitative inspections should be performed to the same predetermined criteria as quantitative inspections by personnel in accordance with ASME Code and through approved site
| |
| -specific programs.
| |
| In its review, the staff determined that the acceptance criteria for these inspections are clearly defined in the program element or in the governing documents. The staff also has no reason to believe that these values, many of which carry the force of regulation, would not allow for the intended function of the components under consideration to be maintained during the period of extended operation under all CLB design loads.
| |
| Based on the above review, the staff confirmed that the "acceptance criteria" program element satisfies the criterion defined in SRP
| |
| -LR Section A.1.2.3.6; therefore, the staff finds it acceptable.
| |
| Operating Experience. LRA Section B.2.2.3 summarizes operating experience related to the Nickel-Alloy Nozzles and Penetrations Program. In this program element, the applicant provided results from six different inspections and, when necessary, the corrective actions that Aging Management Review Results 3-212 were taken as a result of these inspections. The inspections described included hot leg nozzles, lower head penetrations, pressurizer butt welds, steam generator bowl drain connections, pressurizer nozzles, and reactor vessel nozzle butt welds. During these inspections, one axial flaw was discovered in 82/182 weld material in the reactor vessel Loop "D" hot leg nozzle. This flaw was mitigated via the mechanical stress improvement process. Additionally, six pressurizer nozzles were preemptively mitigated via the installation of Alloy 52M full structural weld overlays.
| |
| The staff reviewed this information against the acceptance criteria in SRP
| |
| -LR Section A.1.2.3.10, which states that the operating experience information provided should provide objective evidence that the effects of aging will be adequately managed so that the intended function(s) of the in
| |
| -scope components and structures are maintained during the period of extended operation.
| |
| In this review, the staff found that the applicant was conducting the inspections in accordance with the regulation, the ASME Code, and this AMP. The staff also found that the applicant was correctly responding to the findings of the inspections. Based on the preemptive mitigation conducted by the applicant, the staff concluded that the applicant was appropriately addressing the issue of PWSCC.
| |
| Based on this review, the staff finds that operating experience related to the applicant's program demonstrated that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking appropriate corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10; therefore, the staff finds it acceptable.
| |
| UFSAR Supplement. LRA Section A.2.2.3 provides the UFSAR supplement for the Nickel
| |
| -Alloy Nozzles and Penetrations Program.
| |
| The staff reviewed this UFSAR supplement description of the program and noted that it provides an adequate description of the program. However, the staff also noted that the applicable bulletins, generic letters, and staff
| |
| -accepted industry guidelines are not included in the UFSAR description of the program or commitments.
| |
| By letter dated December 14, 2010, the staff issued RAI B.2.2.3
| |
| -1, requesting that the applicant provide justification to why the applicable bulletins, generic letters, and staff
| |
| -accepted industry guidelines are not necessary in the UFSAR supplement or commitment.
| |
| In its response dated January 13, 2011, the applicant provided a commitment to implementing applicable bulletins, generic letters, and staff
| |
| -accepted industry guidelines.
| |
| The staff finds this response acceptable because the applicant committed to the implementation of applicable bulletins, generic letters, and staff
| |
| -accepted industry guidelines, and is consistent with SRP-LR Table 3.1
| |
| -1, IDs 31 and 34, and their subordinate items. The staff's concern described in RAI B.2.2.3
| |
| -1 is resolved.
| |
| The staff determined that the information in the UFSAR supplement, as amended by the commitment provided, is an adequate summary description of the program, as required by 10 CFR 54.21(d) and is, therefore, acceptable.
| |
| | |
| Aging Management Review Results 3-213 Conclusion. On the basis of its technical review of the applicant's Nickel
| |
| -Alloy Nozzles and Penetrations Program, the staff concludes that the applicant demonstrated that, through the use of this AMP, the effects of aging of nickel alloys will be adequately managed so that the intended function(s) of the components under consideration will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.3.5 Pressurized
| |
| -Water Reactor Vessel Internals Program Summary of Technical Information in the Application. LRA Section B.2.1.7 describes the PWR Vessel Internals Program as plant
| |
| -specific. The applicant stated that the PWR Vessel Internals Program is a new program which manages the aging effect of cracking due to irradiation
| |
| -assisted stress corrosion cracking (IASCC), PWSCC, stress corrosion cracking (SCC), reduction in fracture toughness due to radiation and thermal embrittlement, void swelling, and loss of preload in RVI components.
| |
| In the applicant's letter of May 26, 2015 (ADAMS Accession No. ML15149A279), the applicant redefined the PWR Vessel Internals Program as an AMP that is consistent with the program elements in GALL Report AMP XI.M16A, "PWR Vessel Internals," as updated and defined in ISG LR-ISG-2011-04, "Updated Aging Management Criteria for Reactor Vessel Internal Components for Pressurized Water Reactors." The applicant also submitted an RVI inspection plan that fulfills the conditions and criteria specified in LRA Commitment 1, as provided in LRA Section A.3, "License Renewal Commitment List."
| |
| In the letter of May 26, 2015, as supplemented with information in the letters of October 9, 2015 (ADAMS Accession No. ML15287A396), and December 8, 2015 (ADAMS Accession No. ML15349A896), the applicant also provided its responses to the eight applicant/licensee action items (A/LAIs) for MRP-227-A report.
| |
| In its letters of January 13, 2011 (ADAMS Accession No. ML110140809) and October 9, 2015, the applicant responded to RAIs B.2.1.7
| |
| -1 and 3.0.3.3.5
| |
| -2, which were issued by the staff in order to request additional clarifications on the applicant's bases for dispositioning generic operating experience associated with RVI components that may be made from nickel
| |
| -based alloy materials.
| |
| Staff Evaluation. The staff reviewed the applicant's claim of consistency with GALL Report AMP XI.M16A, as documented in LR
| |
| -ISG-2011-04. The staff compared program elements one through six of the applicant's program to the corresponding program elements of GALL Report XI.M16A. Based on its review, the staff finds that program elements one through six for which the applicant claimed consistency with the GALL Report are consistent with the corresponding program elements of GALL Report AMP XI.M16A.
| |
| The staff also reviewed the applicant's RVI inspection plan (see ADAMS Accession No. ML15149A279) against the inspection and evaluation criteria defined for Westinghouse
| |
| -designed RVI components in the MRP
| |
| -227-A report. The staff verified that the applicant's inspection plan was consistent with the Westinghouse
| |
| -designed internals in MRP
| |
| -227-A, with the exception of component material differences and alternative aging management Aging Management Review Results 3-214 for the flux thimble tubes, which are addressed in the applicant's responses to the A/LAIs on MRP-227-A. The staff's evaluation of the responses to A/LAI Nos. 1, 2, 3, 5, 7, and 8 are given in the paragraphs that follow. A/LAI Nos. 4 and 6 are only applicable to the RVI components designed by the Babcock & Wilcox Company; thus, they are not applicable to the LRA for Seabrook.
| |
| A/LAI No. 1. In A/LAI No. 1, the staff asked the applicant to submit an evaluation to demonstrate that the failure modes, effects, and criticality analyses and functionality analyses for RVI components in MRP
| |
| -227-A are bounding for the design of RVI components at its facility, or else to identify the process that will be used to identify differences in the design of its components from those assessed in MRP
| |
| -227-A. In response to A/LAI No. 1 the applicant demonstrated that the design of the RVI components at Seabrook is within the scope of the assessments in MRP
| |
| -191 report, and EPRI's assumptions for fuel loading, base
| |
| -load operations, and design modifications in the MRP-227-A report. As part of this assessment, the applicant also provided its design
| |
| -specific comparisons to the cold
| |
| -work and fluence assessment criteria for Westinghouse
| |
| -designed RVI components in EPRI Letter No. 2013
| |
| -025 (ADAMS Accession No. ML13322A454). The staff verified that the applicant provided sufficient demonstration that any plant
| |
| -specific RVI components with cold work levels in excess of 20 percent or operating stresses in excess of 30 ksi are already set for augmented inspection per the inspection protocols for the components defined in the MRP
| |
| -227-A report. The staff verified that the applicant also provided sufficient demonstration that the operations for the plant are sufficiently bounded by the following fluence
| |
| -related criteria set in EPRI Letter No. 2013
| |
| -025:
| |
| * 3
| |
| * The maximum average core power density < 124 Watts/cm 3
| |
| * The distance from the top of the active fuel to upper core plate must > 12.2 inches The staff finds that the applicant has adequately addressed A/LAI No. 1 because the applicant has provided sufficient demonstration that the design and operation of RVI components at Seabrook are bounded by the assumptions used to develop the MRP
| |
| -227-A report or else are accounted for in the augmented inspection criteria established in the MRP
| |
| -227-A report. The request in A/LAI No. 1 is resolved.
| |
| A/LAI No. 2. This ALAI asked the applicant to compare the design information for the RVI components at the plant to the corresponding information for the components in Table 4
| |
| -4 of MRP-191. Using the results of this comparison, the staff asked the applicant to identify any changes that would need to be made to the inspection criteria for the components defined in MRP-227-A. The staff reviewed the applicant's response to A/LAI No. 2, which states that the RVI components requiring aging management are consistent with those referenced in MRP
| |
| -191, Table 4-4, and that no additional components were identified. However, the applicant noted that several components were fabricated from different materials than those assumed in either the MRP-227-A or MRP-191 reports. The applicant evaluated these material differences and determined that there was no effect on the recommended aging management strategies in MRP-227-A or else, for the evaluation of the flux thimble tubes, provided an alternative aging management basis for the components. In its response, the applicant provided a list of all RVI Aging Management Review Results 3-215 components in the plant design that were made of a different material from that listed for the components in MRP
| |
| -191. These components were associated with either the upper internals assembly or lower internals assembly in the plant design. The staff reviewed these material differences with the aging management strategy in MR P-227-A and verified that the applicable aging effects for components made of different materials will be adequately managed consistent with the aging management strategy in MRP
| |
| -227-A, with the exception of the inspection strategy for the flux thimble tubes. In regard to the applicant's need for managing aging in the flux thimble tubes, the staff noted that the applicant does not identify any applicable aging effects requiring management for the components and, therefore, does not credit a Flux Thimble Tube Inspection Program. SER Section 3.1.2.1.1 provides the staff's evaluation of the double
| |
| -tubed flux thimble tube design at Seabrook. In this SER section, the staff concluded that cracking and loss of material due to wear are not aging effects that require management for the flux thimble tubes that are included in the plant design.
| |
| The staff finds that the applicant has adequately addressed A/LAI No. 2 because the applicant has identified the RVI components that have designs different from the generic component designs evaluated in MRP
| |
| -191 and has provided sufficient demonstration that the bases for managing these components would not need to be changed from those defined for the components in MRP
| |
| -227-A. For the case of the flux thimble tubes, the staff also finds that the applicant has provided sufficient demonstration that the components do not need to be subject to aging management activities. The request in A/LAI No. 2 is resolved.
| |
| A/LAI No. 3. In ALAI No. 3, the staff requested that applicants for Westinghouse
| |
| -designed units address their aging management needs for the control rod guide tube (CRGT) support pins (split pins) that are included in the plant design due to the potential for cracking to occur in the components. In its response to A/LAI 3, the applicant stated that the original CRGT split pins made from nickel
| |
| -based alloy were proactively replaced with split pins made from cold
| |
| -worked, Type 316 stainless steel in order to mitigate concerns with developing PWSCC in the components. The applicant also stated there currently is no operating experience associated with cracking of CRGT split pins that are made from Type 316 stainless steel materials; therefore, the industry has yet to develop any industrywide guidance for inspecting CRGT split pins made from cold
| |
| -worked, Type 316 stainless steel materials.
| |
| In letters dated January 13, 2011, October 9, 2015, and December 8, 2015, the applicant responded to RAI B.2.1.7
| |
| -1 and 3.0.3.3.5
| |
| -1 and clarified that augmented, plant
| |
| -specific inspections of the split pins are not needed at this time. The applicant stated that its basis for dispositioning the aging management needs for the CRGT split pins at Seabrook is consistent with the inspection criteria in MRP
| |
| -227-A for Westinghouse
| |
| -design CRGT split pins that are made from Type 316, cold worked stainless steel materials. The applicant also stated that there has yet to be any operating experience associated with cracking of split pins made from Type 316 stainless steel materials but clarified that it will reevaluate its inspection needs for the components if the original equipment manufacturer or PWR Owners Group identifies failures on these types of split pins in the future. The applicant has updated the "operating experience" program element of its AMP to indicate that it participates in industry programs for managing aging effects associated with PWR vessel internals, including those developed by the EPRI MRP or the PWR Owners Group.
| |
| | |
| Aging Management Review Results 3-216 The staff finds that the applicant has adequately addressed A/LAI No. 3 because: (1) the applicant justified its determination that the replacement Type 316 stainless steel split pins do not require augmented inspections based on the staff
| |
| -approved program in MRP
| |
| -227-A, and (2) the applicant's activities for participating in the industrywide programmatic initiatives will implement any potentially new inspection protocols for the components if operating experience is generated in future that warrants industry
| |
| -recommended inspections of CRGT split pins made from Type 316 stainless steel materials. Thus, the requests in RAIs B.2.1.7
| |
| -1 and 3.0.3.3.5
| |
| -1, and the request in A/LAI No. 3, are resolved.
| |
| A/LAI No. 5. In A/LAI No. 5, the staff requested that the applicant identify plant
| |
| -specific acceptance criteria to be applied when performing the physical measurements required by MRP-227-A for the loss of compressibility for Westinghouse hold down springs.
| |
| The staff reviewed the applicant's response to A/LAI No. 5, which states that Seabrook is a Westinghouse designed plant and uses a hold
| |
| -down spring that is fabricated from a Type 403 martensitic stainless steel material. The applicant states that the inspection criteria in MRP-227-A for performing physical measurements of the Westinghouse
| |
| -designed RVI holddown springs is only applicable to hold
| |
| -down springs made from Type 304 stainless steel; therefore, this item is not applicable the design of the hold
| |
| -down spring at Seabrook.
| |
| The staff finds that the applicant has adequately addressed A/LAI No. 5 because the applicant has demonstrated and the staff has confirmed that the hold
| |
| -down springs at Seabrook are not fabricated from Type 304 stainless steel and are not within the scope of the augmented inspection criteria for hold
| |
| -down springs made from Type 304 austenitic stainless steel materials. The request in A/LAI No. 5 is resolved.
| |
| A/LAI No. 7. The staff noted that, for Westinghouse
| |
| -designed internals, A/LAI No. 7 specifically addresses the need for managing loss of fracture toughness due to neutron irradiation embrittlement and thermal aging embrittlement in Westinghouse
| |
| -designed lower support column bodies made from CASS, or in any additional RVI components made from CASS or martensitic or precipitation
| |
| -hardened stainless steel materials that were not addressed and dispositioned in the MRP
| |
| -227-A report. For components within the scope of this A/LAI, the staff recommended that the applicant demonstrate adequate management of loss of fracture toughness/thermal aging and neutron irradiation embrittlement in the components through submittal of a component
| |
| -specific evaluation to the NRC for approval; in the A/LAI, the staff specified that an applicable evaluation may be accomplished through performance of either a component-specific flaw tolerance, susceptibility, or functionality analysis.
| |
| In the applicant's response to A/LAI No. 7, the applicant stated that the lower internals assembly-bottom mounted instrumentation (BMI) column cruciforms are fabricated from ASME SA-351, Grade CF8 CASS material. The applicant also stated that the plant design does not include any other RVI components made from CASS or from martensitic or precipitationhardened stainless steel materials that were not appropriately addressed in the MRP-191 and MRP
| |
| -227-A. For the CASS BMI column cruciforms, the applicant calculated the delta ferrite content using the elemental percentages as inputs into Hull's formula per the guidance in NUREG/CR
| |
| -4513, "Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging in LWR Systems." The elemental percentages were obtained from the certified material test reports (CMTRs) for the components. For elements which were not listed in the CMTRs, the applicant Aging Management Review Results 3-217 used 0.04 percent for nitrogen and the 0.5 percent for molybdenum, which are the conservative maximum input values for these alloying elements in the Hull's equation. The applicant stated that the resulting delta ferrite content is less than or equal to the 20
| |
| -percent criteria that staff uses for inducing loss of fracture toughness due to thermal embrittlement in a CASS material. Therefore, the staff finds that the applicant has provided sufficient demonstration that the CASS materials used in the fabrication of the BMI column cruciforms are not susceptible to thermal embrittlement. The staff also verified that the EPRI MRP appropriately dispositioned the BMI column cruciform as "No Additional Measures" components in the MRP
| |
| -227-A report.
| |
| The applicant also stated that the RVI hold
| |
| -down spring is manufactured from Type 403 martensitic stainless steel material. As discussed in the staff's evaluation of the applicant's response to A/LAI 5, the applicant's RVI hold
| |
| -down spring is made from a martensitic stainless steel and is classified as a "No Additional Measures" component per MRP
| |
| -191, Table 6-5. The staff finds that the applicant has adequately addressed A/LAI No. 7 because, for the components made from CASS, martensitic stainless steels, or precipitation
| |
| -hardened stainless steels, the applicant has either: (a) performed the a plant
| |
| -specific evaluation and determined that the components are not susceptible to loss of fracture toughness induced by a thermal embrittlement mechanism, or (b) appropriately evaluated and dispositioned the components as "No Additional Measures" components, consistent with the methodology and guidelines in the MRP-227-A report. The request in A/LAI No. 7 is resolved.
| |
| A/LAI No. 8. In A/LAI No. 8, the staff issued five administrative ARs (subitems) for PWR vessel internals programs that are based on the MRP
| |
| -227-A methodology. The staff reviewed the applicant's responses to A/LAI No. 8 and the five subitems requested in the A/LAI.
| |
| The staff evaluates these responses in the paragraphs that follow.
| |
| A/LAI No. 8, subitem 1, the staff requested that the PWR Vessel Internals AMP for the facility should address the 10
| |
| -program elements as defined for these types of AMPs in GALL Report AMP XI.M16A, "PWR Vessel Internals." The staff verified that, in the applicant's letter of May 26, 2015, the applicant redefined the PWR Vessel Internals Program as an AMP that is consistent with the program elements in GALL Report AMP XI.M16A, "PWR Vessel Internals," as defined in LR
| |
| -ISG-2011-04, "Updated Aging Management Criteria for Reactor Vessel Internal Components for Pressurized Water Reactors." The staff finds that the applicant has adequately addressed A/LAI No. 8, subitem 1, because the applicant has redefined the AMP as a program that is based on the program elements of GALL Report AMP XI.M16A, as revised and updated in LR
| |
| -ISG-2011-04. The administrative action requested in A/LAI No. 8, subitem 1, is resolved.
| |
| In A/LAI No. 8, subitem 2, the staff requested that the LRA's PWR vessel internals AMP include submittal of an RVI inspection plan that addresses the identified plant
| |
| -specific action items for staff review and approval consistent with the licensing basis for the plant. To address A/LAI No.
| |
| 8, subitem 2, the applicant submitted its PWR vessel internals inspection plan with plant
| |
| -specific activities for the primary components, expansion components, existing components, and examination acceptance and expansion criteria for the program in the applicant's letter dated May 26, 2015. The staff noted that the inspection plan was submitted more than 2 years prior to the period of extended operation and fulfills the commitment criteria defined in LRA Commitment 1. The staff finds that the applicant has adequately addressed A/LAI No. 8, subitem 2, because the applicant has submitted its RVI inspection plan as part of the PWR Aging Management Review Results 3-218 Vessel Internals Program in the LRA. The administrative action requested in A/LAI No. 8, subitem 2, is resolved and LRA Commitment 1 is closed.
| |
| In A/LAI No. 8, subitem 3, the staff requested that applicants referencing MRP
| |
| -227-A in their PWR vessel internals AMPs ensure that the programs and MRP
| |
| -based activities for the programs are summarily described in the UFSAR supplement. The staff verified that the applicant included its UFSAR supplement for the PWR Vessel Internals Program in LRA Appendix A, Section A.2.1.7, as amended in the letter dated May 26, 2015. The staff also verified that the UFSAR supplement appropriately summarizes how the programmatic activities defined in the MRP
| |
| -227-A report will be used to manage the effects of aging in the RVI components during the period of extended operation. The staff finds that the applicant has adequately addressed A/LAI No. 8, subitem 3, because the applicant has included its UFSAR Supplement for the AMP in Section A.2.1.7 of the LRA. The staff's review of LRA Section A.2.1.7 is documented below in the "UFSAR Supplement" subsection of this SER section. The administrative action requested in A/LAI No. 8, subitem 3, is resolved.
| |
| In A/LAI No. 8, subitem 4, the staff stated that 10 CFR 54.22, "Contents of Applications
| |
| - Technical Specifications," requires the applicant to submit any TS changes that are necessary to manage the effects of aging during the period of extended operation. In its response to A/LAI 8, subitem 4, the applicant stated that no changes need to be made to the TS based on the implementation of the AMP and MRP
| |
| -227-A during the period of extended operation. The staff reviewed the operating license and TS for Seabrook and verified that they do not include any requirements for inspection or evaluation of RVI components in the plant design. In addition, the staff did not identify any need to amend the operating license or the TS as a result of inspection and evaluation guidelines in MRP
| |
| -227-A. The staff finds that the applicant has adequately addressed A/LAI No. 8, subitem 4, because the staff confirmed that the applicant does not need to propose any TS changes to manage the effects of aging in the plant's RVI components during the period of extended operation. The administrative action requested in A/LAI No. 8, subitem 4, is resolved.
| |
| In A/LAI No. 8, subitem 5, the staff addressed disposition bases for those CUF analyses that may apply to specific RVI components locations and may be defined as TLAAs in the LRA. The staff stated that these types of TLAAs may be dispositioned in accordance with either 10 CFR 54.21(c)(1)(i) or (ii), or 10 CFR 54.21(c)(1)(iii), using an acceptable aging management program, including the an AMP that corresponds to NUREG
| |
| -1801, Revision 2, AMP X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary Program." To satisfy the evaluation requirements of ASME Code, Section III, Subsection NG
| |
| -2160 and NG-3121, A/LAI 8, subitem 5, states that the basis for dispositioning the CUF TLAAs addresses potential impacts of the RCS water environment on the basis for dispositioning the TLAA.
| |
| In its response to A/LAI 8, subitem 5, the applicant stated that the RVI components were designed and constructed prior to the development of ASME Code Section III design requirements for the RVI core support structure components but clarified that the RVI components were analyzed for fatigue as part of the power uprate application for the unit. The applicant stated that the Metal Fatigue of Reactor Coolant Pressure Boundary Program will be used to monitor the number of design cycles assumed in the fatigue analyses to ensure that the design limits will not be exceeded during the period of extended operation. The applicant also stated that the PWR Vessel Internals Program, as enhanced by the MRP
| |
| -227-A report, will be Aging Management Review Results 3-219 used to manage the aging effects that are applicable to the RVI components during the period of extended operation.
| |
| The staff verified that the LRA includes both the PWR Vessel Internals Program and the Metal Fatigue of Reactor Coolant Pressure Boundary Program, which is designed to achieve the following condition monitoring objectives: (a) monitor and track design cycles for design transients assumed in the design basis, (b) provide corrective actions to ensure that the CUF values for the RVI components will not exceed the design limit of 1.0, and (c) evaluate the effects of the reactor coolant environment consistent with the GALL Report. The staff finds that the applicant has adequately addressed A/LAI No. 8, subitem 5, because: (a) the applicant will use both the Metal Fatigue of Reactor Coolant Pressure Boundary Program and the PWR Vessel Internals Program to manage cracking due to fatigue in those RVI components that have been evaluated with a CUF analysis, (b) the programs include program element criteria for either inspecting or monitoring and evaluating the design cycles that are applicable to RVI components with a CUF analysis, and (c) this provides a sufficient basis for evaluating the impacts of the reactor water environment on the basis for dispositioning the CUF values of the components in accordance with 10 CFR 54.21(c)(1)(iii). The administrative action requested in A/LAI No. 8, subitem 5, is resolved.
| |
| Operating Experience. LRA Section B.2.1.7 summarizes operating experience related to the PWR Vessel Internals Program. In this program element, the applicant stated that the previous ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program, Table IWB
| |
| -2500-1, Category B
| |
| -N-3, inspections for Seabrook RVIs have not found any unacceptable indications. It will continue to participate in industry programs related to the aging effects on PWR vessel internals and will implement applicable results into its plant
| |
| -specific AMP.
| |
| The staff reviewed this information against the acceptance criteria in SRP
| |
| -LR Section A.1.2.3.10, which states that the operating experience information should provide objective evidence that the effects of aging will be adequately managed so that the intended function(s) of the in
| |
| -scope components and structures are maintained during the period of extended operation.
| |
| As discussed in the audit report, the staff conducted an independent search of the plant operating experience information to determine if the applicant adequately incorporated and evaluated relevant plant
| |
| -specific or generic operating experience related to this program. During its review, the staff identified operating experience that could indicate that the applicant's program may not be effective in adequately managing aging effects during the period of extended operation. The staff determined the need for additional clarification, which resulted in the issuance of two RAIs related to operating experience and aging management needs for RVI components that may be fabricated from nickel
| |
| -based alloy materials. RAI B.2.1.7
| |
| -1 and the applicant's response are documented in ADAMS Accession No. ML110140809.
| |
| However, the staff determined that further clarifications were needed in relation to determining whether the industry (generic) operating experience associated with the cracking of the Westinghouse
| |
| -design clevis insert bolts is applicable to the design of the clevis insert assemblies and clevis insert bolts at Seabrook. RAI 3.0.3.3.5
| |
| -2 and the applicant's response are documented in ADAMS Accession No. ML15287A396.
| |
| In the applicant's response to RAI 3.0.3.3.5
| |
| -2 dated October 9, 2015, the applicant confirmed that clevis insert bolts for the facility are made from nickel
| |
| -based alloy materials and stated that Aging Management Review Results 3-220 the operating experience associated with cracking in clevis insert bolts is generically applicable to the design of the bolts at Seabrook. The applicant explained that it applied the MRP
| |
| -227-A evaluations to determine its aging management needs for the clevis insert bolts included in the plant design. The applicant stated that the programmatic bases apply the ASME Code Section XI
| |
| -defined ISIs of the components as the condition monitoring basis for assessing the conditions in the components during the life of the plant. The applicant stated that its past ASME Code Section XI 10
| |
| -year ISIs of the clevis insert assemblies and clevis insert bolts did not identify any relevant indications in the assemblies or bolts. The applicant further stated that it participates in the PWR Owners Group and that the future inspections of the clevis insert bolts will consider the recommendations for these components issued by either the EPRI MRP, Westinghouse Electric Company or the PWR Owners Group. The staff finds the response and these aging management bases to be acceptable because: (a) the applicant's aging management basis for the clevis insert bolts is consistent with the basis for managing the components in the MRP
| |
| -227-A report, and (b) the applicant's basis provides reasonable assurance that the applicant will incorporate future operating experience and industry recommendations in its condition monitoring bases for these components during the period of extended operation. RAIs B.2.1.7
| |
| -1 and 3.0.3.3.5
| |
| -2 are resolved with respect to aging management needs for the clevis insert bolts in the plant design.
| |
| Based on its audit, review of the application, and review of the applicant's responses to RAIs, the staff finds that the applicant has appropriately evaluated plant
| |
| -specific and industry operating experience. In addition, the staff finds that the conditions and operating experience at the plant are bounded by those for which GALL Report AMP XI.M16A was evaluated.
| |
| UFSAR Supplement. LRA Section A.2.1.7 provides the UFSAR supplement for the PWR Vessel Internals AMP, as amended by letter dated May 26, 2015. The staff reviewed this UFSAR supplement description of the program and noted that it provides an adequate description of the program and is consistent with the UFSAR supplement example for these types of AMPs provided in SRP
| |
| -LR Table 3.0
| |
| -1, updated in LR
| |
| -ISG-2011-04. The staff noted that the applicant initially committed (refer to LRA Section A.3, Commitment 1) to submitting an inspection plan for the RVI components to the staff for review and approval no less than 24 months prior to entering the period of extended operation. In its letter of April 22, 2011 (ADAMS Accession No. ML11115A116), the applicant updated Commitment 1 to indicate that the PWR Vessel Internals Program will be implemented prior to the period of extended operation and that the plant
| |
| -specific inspection plan for the components will be submitted to the staff within no later than 24 months of receiving the renewed license or 24 months prior to entering into the period of extended operation, whichever comes first.
| |
| In the staff's safety evaluation of MRP
| |
| -227-A, dated December 16, 2011, the action item in A/LAI No. 8, subitem 2, calls for each PWR applicant to submit an RVI inspection plan to the staff for review and approval as part of the LRA's AMP for implementing the MRP
| |
| -227-A report, and in part, to identify and justify any aspects of the inspection plan that may deviate from the approved inspection and evaluation bases for the components in the MRP
| |
| -227-A report.
| |
| In its letter of May 26, 2015, the applicant provided a revised PWR Vessel Internals Program that is based on and designed to be consistent with the programmatic activities in the MRP
| |
| -227-A report. The applicant also submitted an RVI inspection plan for the components consistent Aging Management Review Results 3-221 with the methodology in MRP
| |
| -227-A and identified LRA Commitment 1 as completed and closed. The staff evaluated the changes to Commitment 1 in its review of the applicant's responses to A/LAI No. 8, subitem 2, as documented earlier in this SER section, and finds the closure of Commitment 1 acceptable. As part of this review, the staff verified that the applicant identified, justified, and resolved any deviations from the inspection and evaluation guidelines in the MRP
| |
| -227-A report as part of the applicant's basis for resolving A/LAI No. 2, which the staff has evaluated and dispositioned earlier in this evaluation. The staff also noted that the applicant added Commitment 90 to LRA Appendix A, Table A.3, which states that the applicant will implement the revised PWR Vessel Internals Program in accordance with guidelines in MRP
| |
| -227-A prior to entering into the period of extended operation. Based on the staff's review, the closure of LRA Commitment 1, and the inclusion of LRA Commitment 90, the staff finds that the information in the UFSAR supplement is an adequate summary description of the program.
| |
| Conclusion. On the basis of its technical review of the applicant's PWR Vessel Internals Aging Management Program, the staff concludes that the applicant demonstrated that, through the use of this AMP, the effects of aging of the RVI components will be adequately managed so that the intended function(s) of the components under consideration will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.3.6 Alkali-Silica Reaction Monitoring Program Summary of Technical Information in the Application. By letter dated May 16, 2012, the applicant submitted a new plant
| |
| -specific aging management program, the Alkali
| |
| -Silica Reaction Monitoring Program (ASRMP), to demonstrate that cracking due to expansion from reaction with aggregates will be adequately managed during the period of extended operation. As part of its investigation into why ASR occurred at Seabrook, the applicant conducted a root cause evaluation, which determined that "the concrete mix designs unknowingly utilized an aggregate that was susceptible to ASR." The applicant determined that the aggregate used was slow reactive, even though aggregate reactivity testing was conducted at the time of plant construction in accordance with ASTM C289, "Standard Test Method for Potential Alkali
| |
| -Silica Reactivity of Aggregates (Chemical Method)," and did not detect reactivity. The ASTM C289 standard was subsequently revised to caution that the testing was limited in its ability to identify slow- or late-reacting aggregates.
| |
| Information regarding the applicant's actions to address the ASR issue at Seabrook under its current operating license, including operability assessments, response to confirmatory action letter CAL 2012
| |
| -002, and semi
| |
| -annual review of ASR monitoring, are discussed in a series of NRC Inspection Reports (05000443/2011002, 05000443/2011007, 05000443/2011003, 05000443/2011010, 05000443/2012009, 05000443/2012010, 05000443/2013005, 05000443/2014002, 05000443/2014003, 05000443/2014005, 05000443/2015002, 05000443/2015004, 05000443/2016008, 05000443/2016002, 05000443/2016004, and 05000443/2017004) and the related license amendment request (LAR) 16
| |
| -03, dated August 1, 2016, and LAR Supplement dated September 30, 2016. LAR 16
| |
| -03 requested to amend the Seabrook CLB to add a method for evaluating ASR
| |
| -affected structures at Seabrook and also forms a technical basis for the ASR
| |
| -related AMPs for license renewal. This SER section Aging Management Review Results 3-222 focuses on the staff's evaluation of aging management aspects of ASR degradation for the period of extended operation as part of the staff's review of the LRA); the staff's review of the adequacy of the technical bases supporting the AMP, which are also applicable to the current licensing basis, is documented in the staff's safety evaluation (SE) related to LAR 16
| |
| -03. LRA Section B.2.1.31A describes the ASR Monitoring Program as a plant
| |
| -specific condition monitoring program. The LRA indicates that the existing Structures Monitoring Program, B.2.1.31, and ASME Code Section XI, Subsection IWL Program, B.2.1.28, have been augmented by this program, which is structured according to the guidance in ACI 349.3R, "Evaluation of Existing Nuclear Safety
| |
| -Related Concrete Structures." The LRA states that the AMP addresses concrete structures that are exposed to air outdoor (external), raw water (external), air indoor uncontrolled (external), and soil (external), and proposes to manage cracking due to expansion from reaction with aggregates. The LRA also states that the AMP proposes to manage this aging effect through the performance of periodic visual inspections for indications of ASR and monitoring of the combined cracking index (CCI), individual crack widths, through
| |
| -wall expansions, and volumetric expansion for locations that meet the criteria prescribed in the program.
| |
| The May 16, 2012, LRA Section B.2.1.31A was subsequently revised by letters dated September 13, 2013; May 15, 2014; November 21, 2014; June 30, 2015; December 3, 2015; August 9, 2016; October 3, 2017; November 3, 2017; and May 18, 2018.
| |
| The June 30, 2015, submittal indicated that building deformation had been observed in Seabrook structures. The submittal dated December 3, 2015, revised LRA sections to discuss this aging effect, and subsequent submittals discuss the applicant's approach to managing building deformation due to ASR with a Building Deformation Monitoring Program (BDMP). The staff's review of the plant
| |
| -specific BDMP is documented in Section 3.0.3.3.7 of this SER.
| |
| The LRA describes the mechanism of ASR degradation, and describes a large
| |
| -scale testing program (LSTP) the applicant conducted to research the effects of ASR on structural capacity for certain limit states for which knowledge gaps existed in the literature. The LRA states that the structural assessment of ASR
| |
| -affected structures considered the various limit states for reinforced concrete and applied available literature data to evaluate structural capacity. The applicant identified that there was limited available data for shear capacity and reinforcement anchorage for ASR
| |
| -affected reinforced concrete with t wo-dimensional reinforcement mats, and that the data that existed was not representative of Seabrook structures. The applicant stated that (1) the data for reinforcement anchorage were from a test method that ACI indicated is unrealistic; (2) literature data for shear capacity were from test specimens that were inches in size as compared to the large structures at Seabrook; and (3) no data were available for anchor bolt capacity for concrete similar to Seabrook's two
| |
| -way reinforced structures. Therefore, the applicant opted to perform testing for these limit states. The staff notes that a sufficiently detailed description of the applicant's evaluations of structural limit states and design considerations is contained in Report MPR
| |
| -4288, Revision 0, "Seabrook Station: Impact of Alkali-Silica Reaction on the Structural Design Evaluations" (ADAMS Accession No. ML16216A241), which was submitted to the NRC with LAR 16
| |
| -03. The testing program, which was completed in early 2016, is credited as the technical basis supporting several aspects of the ASRMP and the conclusions of the test program underlie the BDMP structural evaluations. The test report summary, labeled as Report MPR 4273, "Seabrook Station
| |
| - Implication of Large
| |
| -Scale Test Program Results on Reinforced Concrete Affected by ASR,"
| |
| Aging Management Review Results 3-223 dated March 2018 (Seabrook FP# 101050), was submitted by letter dated May 18, 2018. The staff's evaluation of the LSTP and associated bases is discussed in the SE related to LAR 16
| |
| -03 (ADAMS Accession Nos. ML18204A282 (proprietary); ML18204A291 (non
| |
| -proprietary)).
| |
| Staff Evaluation. In support of its review of the ASR Monitoring Program, the NRC staff conducted several onsite audits. During its audits, the staff reviewed the applicant's ASR Monitoring Program against the requirements of 10 CFR Part 54; the guidance provided in SRP-LR Appendix A.1, "Aging Management Review
| |
| -Generic"; and the GALL Report, Revision 2, to verify that the AMP will adequately manage the effects of aging for structures affected by ASR. The table below lists the audit dates, locations, and documentation:
| |
| Dates of Audit Location Audit Report ML November 10
| |
| -13, 2013 Seabrook Station ML13354B785 October 27
| |
| -29, 2015 Ferguson Structural Engineering Laboratory, University of Texas at Austin ML15307A022 (letter)
| |
| ML15337A047 (report)
| |
| October 25
| |
| -27, 2016 Seabrook Station ML16333A247 March 19-22, 2018 Seabrook Station ML18135A046 During its review, the staff required a number of RAIs to address its concerns related to the applicant's proposal to manage the effects of ASR on structure intended functions. As the applicant continued to evaluate the staff's concerns, there were several revisions to the ASR Monitoring Program; Structures Monitoring Program; and ASME Code Section XI, Subsection IWL Program. The staff's evaluation of the Structures Monitoring Program and ASME Code Section XI, Subsection IWL Program are documented in SER Sections 3.0.3.2.18 and 3.0.3.2.17, respectively. However, because the ASR Monitoring Program includes all Seabrook concrete structures in the scope of license renewal, including primary containment, the staff's review of the applicant's program for managing the effects of ASR (including ASR
| |
| -related correspondence that occurred prior to the applicant submitting the plant
| |
| -specific ASR Monitoring Program) is primarily discussed in this section. Unless otherwise noted, the staff's evaluation relates to the latest version of the ASR Monitoring Program. Previous versions of the AMP and prior RAIs are only discussed as necessary to support the staff's conclusions. The RAIs and the responses are discussed briefly below, followed by the staff's evaluation of each of the program elements in the latest version of the ASR Monitoring Program (dated May 18, 2018). This section includes a summary of public meetings that occurred between the applicant and the staff throughout the review period and also notes when supplements were submitted.
| |
| * RAIs B.2.1.28
| |
| -3 and B.2.1.31
| |
| -1, issued by letter dated November 18, 2010: RAI B.2.1.28-3 requested details regarding the potential presence of ASR in the containment building concrete due to the accumulation of water in the annulus area between the containment and the containment enclosure building. RAI B.2.1.31
| |
| -1 requested Aging Management Review Results 3-224 information regarding the results of concrete tests and plans to manage the effects of aging.
| |
| * RAI B.2.1.28
| |
| -3 and B.2.1.31
| |
| -1 responses provided by letter dated December 17, 2010: The applicant provided information regarding containment inspections (RAI B.2.1.28
| |
| -3 response) and a summary of concrete testing results and indicated that an extent of condition investigation was initiated and that the Structures Monitoring Program would manage the effects of aging (RAI B.2.1.31
| |
| -1 response). The letter included Commitment 51 (subsequently withdrawn by letter dated August 11, 2011) to perform confirmatory testing and evaluation of the containment building, and Commitment 52 to implement measures to maintain the annulus (i.e., the exterior surface of the Containment Structure, from elevation
| |
| -30 ft to +20 ft) in a dewatered state.
| |
| * Followup RAI B.2.1.31
| |
| -1, issued by letter dated March 17, 2011: Followup RAI B.2.1.31
| |
| -1 requested additional information regarding the "extent of condition" investigation, including a discussion of planned tests, estimated timeframe, and plan to address ASR.
| |
| * Followup RAI B.2.1.31
| |
| -1 response provided by letter dated April 14, 2011: The applicant indicated that the "extent of condition" was scheduled to be completed in June 2011 and provided high
| |
| -level information regarding its action plan to address ASR.
| |
| * Followup RAIs B.2.1.28
| |
| -3 and B.2.1.31
| |
| -1, issued by letter dated June 29, 2011: Followup RAI B.2.1.28
| |
| -3 requested clarification as to whether Commitment 51 remains valid and details for plans to monitor cracking due to expansion from reaction with aggregates on the containment building. Followup RAI B.2.1.31
| |
| -1 requested detailed and comprehensive information regarding the applicant's planned approach to addressing ASR throughout the site.
| |
| * Followup RAI B.2.1.28
| |
| -3 and B.2.1.31
| |
| -1 responses provided by letter dated August 11, 2011: The applicant indicated that confirmatory testing on the containment building cannot be made until the aging effects are fully understood (Followup RAI B.2.1.28-3 response) and that detailed information regarding the planned approach to addressing ASR throughout the site will be included in an engineering evaluation scheduled to be completed in March 2012 (Followup RAI B.2.1.28
| |
| -3 and B.2.1.31
| |
| -1 responses).
| |
| * Followup RAI B.2.1.31
| |
| -1 response and supplemental responses to RAIs B.2.1.28
| |
| -3, B.2.1.31-1, provided by letter dated March 30, 2012: The applicant indicated that a walkdown had been performed to assess the accessible portion of concrete structures and that it had "initiated actions to perform testing on full
| |
| -scale replicas of station structural configurations" (i.e., the LSTP) (Followup RAI B.2.1.31
| |
| -1 response). The applicant also indicated that, based on inspections of the containment building in September 2011, two locations exhibiting pattern cracking will be monitored in Tier 2 (second of three "Tiers" of ASR cracking severity) of the Structures Monitoring Program (RAI B.2.1.28
| |
| -3 supplemental response). Based on ongoing tests and analyses, supplemental responses were provided for RAI B.2.1.31
| |
| -1 and Followup RAI B.2.1.31
| |
| -1 to include the most current information.
| |
| * Plant-Specific ASR Monitoring Program provided as a supplement to the LRA by letter dated May 16, 2012: This supplement provided the initial plant
| |
| -specific AMP, Aging Management Review Results 3-225 augmenting the Structures Monitoring Program, to address cracking due to expansion from reaction with aggregates.
| |
| * Followup RAIs B.2.1.28
| |
| -3 and B.2.1.31
| |
| -1, and RAIs B.2.1.31
| |
| -5, -6, -7, -8, -9, -10, and -11, issued by letter dated September 14, 2012: Followup RAI B.2.1.28
| |
| -3 requested clarifying information regarding the aging management of cracking due to expansion from reaction with aggregates for the containment building. Followup RAI B.2.1.31
| |
| -1 requested clarifying information regarding the parameters monitored or inspected and acceptance criteria for the ASR Monitoring Program. RAI B.2.1.31
| |
| -5 requested clarification as to whether visual inspections would be used to rule out the presence of ASR in a concrete structure. RAI B.2.1.31
| |
| -6 requested the technical basis for the acceptance criteria proposed. RAI B.2.1.31
| |
| -7 requested information to determine if monitoring was being proposed for a sample of the population meeting the acceptance criteria. RAI B.2.1.31
| |
| -8 requested plans for the inspection of rebar, anchor bolts, and embedments. RAI B.2.1.31
| |
| -9 requested information regarding the inspection of inaccessible areas. RAI B.2.1.31-10 requested clarification as to whether preventive or mitigative actions would be taken. RAI B.2.1.31
| |
| -11 requested clarification on the scope of the Structures Monitoring Program.
| |
| * Followup RAI B.2.1.28
| |
| -3 and B.2.1.31
| |
| -1, and RAIs B.2.1.31
| |
| -5, -6, -7, -8, -9, -10, and -11 responses provided by letter dated November 2, 2012: The applicant explained that the containment building is within the scope of the ASR Monitoring Program and areas exhibiting characteristics of ASR will be monitored accordingly (Followup RAI B.2.1.28
| |
| -3 response). The applicant also explained that the parameters monitored are intended to monitor and trend cracking due to expansion from reaction with aggregates and that the acceptance criteria to be followed is that in the ASR Monitoring Program (Followup RAI B.2.1.31-1 response). The applicant further explained that visual inspection will not be used to rule out the presence of ASR (RAI B.2.1.31
| |
| -5 response) and that the technical basis for the acceptance criteria was derived from three publications (RAI B.2.1.31
| |
| -6 response). The applicant provided information regarding the inspection of rebar, anchor bolts, and embedments (RAI B.2.1.31
| |
| -8 response) and the inspection of inaccessible areas of concrete (RAI B.2.1.31
| |
| -9 response). The applicant indicated that preventive action or mitigative measures will not be relied upon for aging management (RAI B.2.1.31-10 response) and that the scope of the ASR Monitoring Program includes all concrete structures within the scope of license renewal (RAI B.2.1.31
| |
| -11 response).
| |
| * Supplemental response to Followup RAI B.2.1.31
| |
| -1 provided by letter dated November 20, 2012: The applicant revised the response to Followup RAI B.2.1.31
| |
| -1 to explain that the results of the LSTP will be used in structural evaluations and that, in the event the results indicate the need to amend the acceptance criteria or inspection frequency, action will be taken under the "operating experience" program element.
| |
| * Supplement to the ASR Monitoring Program provided by letter dated September 13, 2013: The applicant supplemented the ASR Monitoring Program and UFSAR supplement to address the staff's concerns, expressed during a February 21, 2013, public meeting held to discuss the additional information needs of the staff.
| |
| * RAIs B.2.1.31A
| |
| -1, -2, -3, -4, -5, and -6, issued by letter dated January 15, 2014: RAI B.2.1.31A-1 requested clarification regarding the ASR Monitoring Program augmentation of the ASME Code Section XI, Subsection IWL Program. RAI B.2.1.31A
| |
| -2 requested information regarding the number of locations being monitored and the basis for Aging Management Review Results 3-226 frequency of inspection. RAI B.2.1.31A-3 requested clarification as to the timing of the transition of Tier 2 locations from "qualitative monitoring" to "quantitative monitoring." RAI B.2.1.31A
| |
| -4 requested information regarding the role of large
| |
| -scale testing with respect to the AMP.
| |
| RAI B.2.1.31A
| |
| -5 requested an explanation as to how monitoring surface cracks is sufficient to monitor progression of ASR. RAI B.2.1.31A
| |
| -6 requested additional information regarding the inspection of inaccessible areas of concrete structures.
| |
| * RAI B.2.1.3 1A-1, -2, -3, -4, -5, and -6 responses provided by letter dated May 15, 2014: The applicant revised the ASR Monitoring Program to indicate that it also augments the ASME Code Section XI, Subsection IWL Program (RAI B.2.1.31A
| |
| -1 response). The applicant explained that all locations meeting Tier 2 or Tier 3 criteria will be monitored at the specified interval and provided the basis for the frequency of inspection (RAI B.2.1.31A
| |
| -2 response). The applicant provided information regarding the transition between qualitative monitoring and quantitative monitoring (RAI B.2.1.31A
| |
| -3 response) and revised the UFSAR to clarify the role of large
| |
| -scale testing (RAI B.2.1.31A
| |
| -4). The applicant committed (Commitment 83) to installing instrumentation (i.e., extensometers) in sample areas to determine if monitoring expansion in the out
| |
| -of-plane direction is necessary (RAI B.2.1.31A
| |
| -5 response), explained that the ASR Monitoring Program will be used to monitor inaccessible areas meeting the criteria, and revised Commitment 67 to indicate that the core being removed from the spent fuel pool (inaccessible area that was continuously wetted from borated water) will be examined for the presence of ASR (RAI B.2.1.31A
| |
| -6 response).
| |
| * Supplemental response to RAI B.2.1.31A provided by letter dated November 21, 2014: The applicant clarified its response to RAI B.2.1.31A based on discussions during a September 30, 2014, teleconference with the staff.
| |
| * RAIs B.2.1.31A
| |
| -2(a), -5(a), and
| |
| -6(a), and RAI B.2.1.31A
| |
| -7, issued by letter dated November 25, 2014: RAI B.2.1.31A
| |
| -2(a) requested clarification as to whether monitoring and trending results would be used to adjust the frequency of inspection such that it would exceed the 5
| |
| -year inspection interval accepted for concrete inspections per ACI 349.3R. RAI B.2.1.31A
| |
| -5(a) expressed the staff's concerns regarding the adequacy of four of the AMP program elements and requested that the applicant provide sufficient information to address the staff's concerns. RAI B.2.1.31A
| |
| -6(a) requested information as to whether actions will be taken to confirm that the magnitude of cracking in inaccessible areas is not greater than that observed on accessible surfaces.
| |
| RAI B.2.1.31A
| |
| -7 requested clarification as to whether there are structures monitored on a 10-year inspection interval, as opposed to a 5
| |
| -year interval, and justification that the 10-year interval will be adequate for identifying new areas affected by ASR.
| |
| * RAI B.2.1.31A
| |
| -2(a) and B.2.1.31A
| |
| -7 responses provided by letter dated February 23, 2015: In the RAI B.2.1.31A
| |
| -2(a) response, the applicant explained that inspection frequencies of Tier 3 and Tier 2 areas currently specified in the ASR Monitoring Program may change, based on trending; however, the inspection frequencies will not exceed the 5
| |
| -year frequency specified in the Structures Monitoring Program for areas in a harsh environment. In the RAI B.2.1.31A
| |
| -7 response the applicant provided the Structures Monitoring Program definitions of a "harsh environment" and a "mild environment." Based on the definitions, the applicant explained that ASR is not expected and has not been detected in a "mild environment," because it lacks sufficient moisture to produce ASR. The applicant also explained that Aging Management Review Results 3-227 structures in a harsh environment are inspected on a 5
| |
| -year interval and those in a mild environment, in which conditions favorable for ASR are not present, are inspected on a 10-year interval.
| |
| * RAI B.2.1.31A
| |
| -5(a) and B.2.1.31A
| |
| -6(a) responses provided by letter dated June 30, 2015 (ADAMS Accession No. ML15183A023): Response to RAI B.2.1.31A
| |
| -5(a) regarding the use of LSTP data to inform monitoring methods and locations at Seabrook. Specifically, the response provided the technical basis for using CCI for in
| |
| -plane (x-y direction) expansion and extensometers for out
| |
| -of-plane (through thickness or z direction) expansion. Commitment 83 was updated to include measurement of out
| |
| -of-plane expansion with extensometers and Commitment 91 was added to address monitoring building displacements. In the response to RAI B.2.1.31A6(a), the applicant stated that it will perform opportunistic or focused inspections of inaccessible concrete to ensure that the extent of ASR degradation is bounded by inspection results from accessible concrete. This submittal also included MPR-4153, "Seabrook Station Approach for Estimating Through
| |
| -Thickness Expansion from AlkaliSilica Reaction" (ADAMS Accession No. ML15183A020).
| |
| * RAIs B.2.1.31A
| |
| -8, B.2.1.31A
| |
| -5(a1) to -5(a4), issued by letter dated October 2, 2015 (ADAMS Accession No. ML15251A333): RAI B.2.1.31A
| |
| -8 requested that the applicant address operating experience of building deformation and large macro cracking. RAI B.2.1.31A-5(a1) requested that the applicant justify the representativeness of the LSTP to Seabrook structures. RAI B.2.1.31A
| |
| -5(a2) requested that the applicant provide information related to uncertainties in the estimate of normalized modulus of elasticity used in MPR
| |
| -4153. RAI B.2.1.31A
| |
| -5(a3) requested information to justify the number of through-wall extensometer locations proposed for monitoring. RAI B.2.1.31A
| |
| -5(a4) requested that the applicant provide details on the specifics of how the CCI would be used to monitor degradation and how it would account for strain in the concrete and rebar.
| |
| * Responses to RAI B.2.1.31A
| |
| -8, and B.2.1.31A
| |
| -5(a1) to -5(a4) provided by letter dated December 3, 2015 (ADAMS Accession No. ML15343A470): In response to RAI B.2.1.31A
| |
| -8, the applicant added building deformation operating experience to its ASR Monitoring AMP and reflected such in revised Commitment 91.
| |
| In response to RAI B.2.1.31A-5(a1), the applicant provided specific information in relation to its LSTP related to methodology and intent of the testing, as well as how the data will apply to Seabrook. In response to RAI B.2.1.31A
| |
| -5(a2), the applicant further discussed its methodology for estimation of through
| |
| -wall expansion to date. It also alluded to a Revision 2 of MPR
| |
| -4153 that would include expanded discussions to address the staff's questions. In its response to RAI B.2.1.31A
| |
| -5(a3), the applicant revised its approach for monitoring through
| |
| -thickness expansion to install extensometers in all Tier 3 locations and added such to Commitment 83. In its response to RAI B.2.1.31A
| |
| -5(a4), the applicant stated that it will monitor volumetric effects of ASR and provided detailed discussion of the technical methodology underlying its proposed approach. In this submittal, the applicant also provided an updated LRA Section B.2.1.31A.
| |
| Staff held a public meeting on April 28, 2016, to discuss technical issues related to the applicant's December 3, 2015, submittal. The meeting summary was issued on June 8, 2016 (ADAMS Accession No. ML16146A172).
| |
| | |
| Aging Management Review Results 3-228 By letter dated August 9, 2016, the applicant submitted a supplement to its LRA (ADAMS Accession No. ML16224B079) providing additional information as discussed with the staff during the April 28, 2016, public meeting. The applicant also submitted an updated ASRMP AMP that superseded the previous submittal, and an additional plant
| |
| -specific BDMP. The staff's review of the BDMP is in SER Section 3.0.3.3.7. In addition, in August 2016, the applicant also submitted LAR 16
| |
| -03 to the NRC requesting an amendment to its operating license to account for ASR effects. The applicant indicated that the AMPs are consistent with the methodologies presented in LAR 16
| |
| -03 and that any changes resulting from NRC's review of the LAR would be reflected in the AMPs. The staff performed an onsite audit October 25
| |
| -27, 2016, to review the applicant's AMP submittal (ADAMS Accession No. ML16333A247). RAIs B.2.1.31A
| |
| -A1, B.2.1.31A
| |
| -A2, B.2.1.31A
| |
| -A3, and B.2.1.31A
| |
| -A4 (based on the audit of the applicant's August 9, 2016, submittal) issued by letter dated November 30, 2016 (ADAMS Accession No. ML16326A037): RAI B.2.1.31A
| |
| -A1 requested that the applicant discuss the way it was crediting volumetric expansion measurements and state how the program will use CCI to manage ASR
| |
| -induced rebar stresses and strains such that they remain within design code limits. RAI B.2.1.31A
| |
| -A2 requested that the applicant clarify the inspection interval planned for monitoring through
| |
| -wall expansion. RAI B.2.1.31A
| |
| -A3 requested that the applicant clarify whether the structural evaluations referred to in the ASR Monitoring Program are the same as those performed in the BDMP. RAI B.2.1.31A
| |
| -A4 requested that the applicant state how it will validate and verify the behavior of ASR
| |
| -affected structures as modeled in the LSTP.
| |
| Responses to RAIs B.2.1.31A
| |
| -A1, -A2, -A3, and -A4 and clarifications to its ASR Monitoring program and related commitments provided by letter dated December 23, 2016 (ADAMS Accession No. ML16362A283): In its response to RAI B.2.1.31A
| |
| -A1, the applicant explained and provided the technical basis for how volumetric expansion will be monitored and assessed. It also stated that it will evaluate rebar stresses and strains relative to the applicable design code. In its response to RAI B.2.1.31A
| |
| -A2, the applicant stated that snap
| |
| -ring borehole extensometer measurements will be conducted on a six
| |
| -month frequency. In its response to RAI B.2.1.31A
| |
| -A3, the applicant confirmed that the structural evaluations referenced in the ASR Monitoring Program are those being carried out in the BDMP. In its response to B.2.1.31A
| |
| -A4, the applicant detailed its plans for future corroboration of the correlation between modulus of elasticity and through
| |
| -wall expansion to
| |
| -date. The applicant added two Commitments for the corroboration activities: Commitment 45 was added to corroborate the methodology described in MPR-4153 at least two (subsequently changed to five) years prior to PEO and 10 years thereafter; and Commitment 66, which stated that the applicant will conduct a periodic assessment of ASR expansion behavior at least 5 years prior to PEO and every 10 years thereafter. In this submittal, the applicant also included an updated LRA Section B.2.1.31A.
| |
| RAI B.2.1.31A
| |
| -A1-1, B.2.1.31A
| |
| -A4-2 issued by letter dated March 29, 2017 (ADAMS Accession No. ML17088A614): RAI B.2.1.31A
| |
| -A1-1 requested justification for not having acceptance criteria for volumetric expansion. RAI B.2.1.31A
| |
| -A4-2 requested information regarding acceptance criteria associated with the planned corroboration studies, and justification for why taking three cores at one point in time will sufficiently corroborate conclusions from the LSTP being applicable to Seabrook structures.
| |
| Responses to RAIs B.2.1.31A
| |
| -A1-1 and B.2.1.31A
| |
| -A4-2, dated October 3, 2017 (ADAMS Accession No. ML17277B519): In response to RAI B.2.1.31A
| |
| -A1-1, the applicant stated that it will incorporate volumetric expansion as a new monitoring parameter in the "parameters Aging Management Review Results 3-229 monitored or inspected," "detection of aging effects," and "monitoring and trending" program elements and provided acceptance criteria in the "acceptance criteria" program element. The frequency of examination will be consistent with the monitoring intervals for the in
| |
| -plane and through-wall expansion measurements. In response to RAI B.2.1.31A
| |
| -A4-2, the applicant modified its proposal to corroborate in
| |
| -situ expansion behavior with the LSTP (see "operating experience" program element in Section 3.0.3.3.6 below).
| |
| By letter dated November 3, 2017 (ADAMS Accession No. ML17307A027), the applicant submitted a revised ASR Monitoring Program.
| |
| By letter dated December 11, 2017 (ADAMS Accession No. ML18141A785), the applicant submitted a Methodology Document that the applicant stated serves as a basis for the ASR Monitoring Program. The staff performed an on
| |
| -site audit from March 19
| |
| -22, 2018, to review the applicant's submittal (ADAMS Accession No. ML18135A046).
| |
| The staff reviewed program elements one through six, and ten, of the applicant's ASR Monitoring Program against the acceptance criteria for the corresponding elements as stated in SRP-LR Section A.1.2.3. The staff's review focused on how the applicant's program manages cracking due to expansion from reaction with aggregates through the effective incorporation of these program elements. The staff verified that program elements seven through nine, "corrective actions," "confirmation process," and "administrative controls," were consistent with the guidance in SRP
| |
| -LR Appendix A.1, during the audit conducted on November 18
| |
| -20, 2013. The staff also noted during its March 19
| |
| -22, 2018, audit that these program elements are being effectively implemented. The staff's evaluation of these program elements is documented in SER Section 3.0.4. As stated earlier in this section, the applicant also applied to amend its CLB to account for the effects of ASR. In its review of this LAR (LAR 16
| |
| -03), the staff assessed the technical adequacy of the applicant's LSTP, which is credited as a basis for the ASR Monitoring Program. The staff's review is documented in its Safety Evaluation Related to LAR 16
| |
| -03 (ADAMS Accession Nos. ML18204A282 (proprietary); ML18204A291 (non
| |
| -proprietary)). Therefore, the staff's evaluation of the adequacy of the testing methodology and the conclusions from the LSTP credited in the ASR Monitoring Program will not be discussed in this SER. Scope of Program. LRA Section B.2.1.31A states that the scope of the program includes concrete structures within the scope of the Structures Monitoring Program and the ASME Code Section XI, Subsection IWL Program. The program proposes to manage the aging effect of cracking due to expansion from reaction with aggregates during the period of extended operation. The LRA lists the specific Seismic Category 1 structures, Miscellaneous Non
| |
| -seismic Category 1 yard structures, and Non
| |
| -Category 1 structures included in the scope of license renewal.
| |
| The staff reviewed the applicant's "scope of program" program element against the criteria in SRP-LR Section A.1.2.3.1, which state that the scope of the program should include the specific structures and components, the aging of which the program manages. During an onsite audit, the staff verified that all concrete structures within the scope of license renewal are included in the ASR Monitoring Program.
| |
| The staff finds the applicant's "scope of program" program element to be adequate because the LRA clearly identifies all concrete structures within the scope of the program and the staff Aging Management Review Results 3-230 confirmed that all concrete structures within the scope of license renewal are included in the AMP. Based on its review of the application as documented in a letter dated May 18, 2018, the staff confirmed that the "scope of program" program element satisfies the criteria defined in SRP
| |
| -LR Section A.1.2.3.1; therefore, the staff finds it acceptable.
| |
| Preventive Actions. LRA Section B.2.1.31A states that the ASR Monitoring Program is a condition monitoring program and does not rely on preventive actions to manage cracking du e to expansion from reaction with aggregates. The staff reviewed the applicant's "preventive actions" program element against the criteria in SRP
| |
| -LR Section A.1.2.3.2, which state that some condition monitoring programs do not rely on preventive actions.
| |
| However, SRP
| |
| -LR Section A.1.2.3.2 also states that in cases for which the condition monitoring programs may rely on preventive actions, the preventive activities should be specified.
| |
| The staff finds the applicant's "preventive actions" program element to be adequate because the ASR Monitoring Program is a condition monitoring program that does not rely on preventive actions or mitigation measures and, therefore, any mitigation measures taken need not be specified within this program element.
| |
| Based on its review of the application as documented in a letter dated May 18, 2018, the staff confirmed that the "preventive actions" program element satisfies the criteria defined in SRP
| |
| -LR Section A.1.2.3.2; therefore, the staff finds it acceptable.
| |
| Parameters Monitored or Inspected. LRA Section B.2.1.31A states that an initial screening process will look for visual characteristics at the surface of concrete, which typically include "map" or "pattern" cracking, surface discoloration of the cement paste surrounding the cracks, and the presence of moisture and efflorescence. The LRA states that inaccessible areas of concrete will be inspected during opportunistic or focused inspections for buried concrete every five years. The LRA also states that petrographic examination may be performed on concrete specimens to aid in the confirmation of the proposed diagnosis from visual inspections.
| |
| The applicant stated that for the initial assessment of ASR
| |
| -affected structures, it will assess the extent of ASR damage by in
| |
| -plane expansion measurements using the Cracking Index (summation of measurement of crack widths along a vertical or horizontal side of a section of concrete surface) on 20 inch by 30 inch grids and establish the Combined Cracking Index (CCI) for that area. The CCI is calculated by summing the widths of all cracks crossing the grid lines and dividing the sum by the total grid line length. The LRA also states that this process is described in the "Report on the Diagnosis, Prognosis, and Mitigation of Alkali
| |
| -Silica Reaction (ASR) in Transportation Structures," by the Federal Highway Administration. The LRA further states that the criteria used in assessment of expansion are based on recommendations provided in MPR
| |
| -3727, Revision 0, "Seabrook Station: Impact of Alkali-Silica Reaction on Concrete Structures and Attachments" and are supported by the LSTP.
| |
| The LRA states that for monitoring ASR progression, it will obtain measurements in both the in
| |
| -plane and through
| |
| -thickness directions. For the in
| |
| -plane expansion, the applicant will monitor the CCI and/or embedded pin measurements. The staff noted during its on
| |
| -site audit that the decision whether to monitor CCI or embedded pin measurements is based on which value is most dependably measurable in each area. The applicant stated that below 1 mm/m, direction of expansion is not significantly affected by the concrete reinforcement and thus for low Aging Management Review Results 3-231 expansion levels monitoring only the in
| |
| -plane expansion is adequate. The applicant stated that the LSTP showed that for structures with two
| |
| -dimensional reinforcement mats in the in
| |
| -plane directions (the configuration for many Seabrook structures), in
| |
| -plane expansion plateaued at low expansion levels, while expansion in the through
| |
| -thickness direction continued to increase. Therefore, for ASR expansion greater than a CCI of 1 mm/m ("Tier 3" locations), the applicant intends to monitor the effects of ASR expansion by also measuring through
| |
| -wall expansion using extensometers, and combined volumetric expansion.
| |
| In order to determine the total ASR
| |
| -induced through
| |
| -thickness expansion at each extensometer location, the applicant proposes to first determine the expansion at the time the extensometer is installed. The proposed method to determine expansion to
| |
| -date is based on a correlation established in the LSTP between reduction in modulus of elasticity and through
| |
| -wall expansion. The applicant will take cores at each extensometer location, test for the modulus of elasticity, and relate the reduction in modulus to establish expansion at the time of extensometer placement; the correlated value will then be added to the measured expansion. The staff notes that this methodology is described in Report MPR
| |
| -4153, "Seabrook Station
| |
| - Approach for Determining Through
| |
| -Thickness Expansion from Alkali
| |
| -Silica Reaction," Revision 3 (September 2017), which was submitted to the NRC in support of LAR 16
| |
| -03. The LRA states that based on the LSTP results, structural evaluations regarding ASR micro cracking should consider that there has been no adverse impact on the flexure/reinforcement anchorage and shear limit states provided that through
| |
| -thickness and volumetric expansion are at or below bounding conditions of the LSTP, and expansion behavior is comparable to the test specimens, and there is no adverse impact on anchor/embedment capacity provided that in
| |
| -plane expansions remain below the tested limits.
| |
| The applicant states that the inspection of inaccessible areas of concrete will be performed during opportunistic or focused inspections for buried concrete performed under the Maintenance Rule every five years. The staff confirmed during its ASR
| |
| -focused Inspection Procedure (IP) 71002 inspection (conducted May 1
| |
| -3, 2018) that the applicant will include a periodic maintenance task to trigger focused inspection of inaccessible concrete if no opportunistic inspections have been conducted during the monitoring interval.
| |
| The staff reviewed the applicant's "parameters monitored or inspected" program element against the criteria in SRP
| |
| -LR Section A.1.2.3.3, which state that the program element should identify the aging effects that the program manages and provide a link between the parameters being monitored and how monitoring those parameters will ensure adequate aging management. SRP
| |
| -LR Section A.1.2.3.3 also states that, for condition monitoring programs, the parameter monitored or inspected should be capable of detecting the presence and extent of aging effects.
| |
| The staff notes that as evidenced through correspondence with the applicant noted above, the program has been revised several times and the applicant's bases supporting the "parameters monitored or inspected" program element have been docketed. The staff also notes that the technical adequacy of the LSTP has been reviewed by the staff and the conclusions of the LSTP have been found to be acceptable. The staff's review of the technical aspects of the LSTP is documented in the SE related to LAR 16
| |
| -03. The staff finds the applicant's "parameters monitored or inspected" program element to be adequate because:
| |
| | |
| Aging Management Review Results 3-232 (1) The program uses visual inspections, in accordance with GALL Report recommendations, to identify ASR suspect areas for additional monitoring (e.g., CCI or embedded pins).
| |
| (2) CCI was found to correlate with concrete strain values that were directly measured in the LSTP and wherever possible embedded pins will be used to directly measure concrete and rebar strain (rebar strain is also discussed in SER Section 3.0.3.3.7).
| |
| (3) ASR expansion is being monitored using in
| |
| -plane, through
| |
| -wall, and volumetric measurement, which is appropriate since ASR expansion occurs in all directions. The LSTP considered volumetric expansion and observed no adverse structural implications for the limit states tested.
| |
| (4) MPR-4288, "Seabrook Station: Impact of Alkali-Silica Reaction on Structural Design Evaluations" (submitted as part of LAR 16
| |
| -03), discusses the applicant's rationale for choosing the limit states and design considerations to be examined for the LSTP; and the staff determined that the chosen limit states are bounding of potential impact to intended function of ASR
| |
| -affected structures. The parameters monitored in the ASR Monitoring Program are the same as those monitored in the LSTP.
| |
| (5) The LSTP confirmed that at low levels of ASR progression, in
| |
| -plane and through
| |
| -wall cracking are generally similar. The staff agrees that monitoring less severe ASR locations initially via CCI and embedded pins, and installing an extensometer once ASR has progressed greater than 1 mm/m, will allow the program to identify severity of ASR progression. This conclusion will be confirmed prior to the period of extended operation and periodically thereafter (Commitment 66).
| |
| (6) A reduction in modulus of elasticity was correlated to through
| |
| -wall expansion measurements and confirmed for structures studied in the LSTP. This allows for total expansion to be known for Seabrook structures such that it can be compared to expansion levels tested. The applicant committed (Commitment 66) to corroborate that correlation prior to the period of extended operation and periodically thereafter.
| |
| (7) In its June 30, 2015, response to RAI B.2.1.31a
| |
| -5(a), the applicant stated that core bores removed to install the out
| |
| -of-plane extensometers will be inspected to rule out laminar cracking in Tier 3 locations, and that 34 cores removed did not reveal any evidence of laminar cracking. The applicant committed (Commitment 66) to periodically inspect cores for mid
| |
| -plane cracking when removed for each corroboration study.
| |
| (8) The AMP includes opportunistic or focused inspections of inaccessible areas. In addition, as stated in the applicant's June 30, 2015, response to RAI B.2.1.31a
| |
| -6(a), several inspections of inaccessible areas have been performed; and results to date have confirmed that the levels of ASR observed in inaccessible areas have been consistent with that observed in accessible areas.
| |
| Based on its review of the application, as revised by letter dated May 18, 2018, and review of the applicant's response to RAIs, the staff confirmed that the "parameters monitored or inspected" program element satisfies the criteria defined in SRP
| |
| -LR Section A.1.2.3.3; therefore, the staff finds it acceptable.
| |
| Detection of Aging Effects. LRA Section B.2.1.31A states that monitoring walkdowns are performed on a periodic basis. The Structures Monitoring Program performs visual inspections to identify areas that indicate ASR and require expansion measurements in accordance with the Aging Management Review Results 3-233 ASR Monitoring Program AMP. For in
| |
| -plane expansion, the CCI of ASR
| |
| -affected areas is measured. The frequency of Tier 2 (CCI < 1.0 mm/m) location inspections is every 2.5 years. -month basis. The LRA states that for areas where the structural evaluations performed under the BDMP indicate more frequent CCI or pin
| |
| -to-pin monitoring is required, the program defaults to the more frequent interval. Tier 3 areas will also be monitored in the through
| |
| -thickness direction with Snap
| |
| -Ring Borehole Extensometers (SRBEs). The LRA states that the applicant evaluated the performance of several instrument types over the course of a year and that the SRBE was chosen because of its reliable performance. The LRA states that cores removed for installation of SRBEs will be visually examined to confirm the absence of a mid
| |
| -plane crack. For volumetric expansion, the program will monitor volumetric expansion using the CCI and extensometer measurements at Tier 3 locations on a six-month interval.
| |
| The staff reviewed the applicant's "detection of aging effects" program element against the criteria in SRP
| |
| -LR Section A.1.2.3.4, which state that the program element should address how the program would detect the occurrence of age
| |
| -related degradation, prior to a loss of intended function. This element should also discuss "when," "where," and "how" data will be collected. For condition monitoring programs, the SRP
| |
| -LR states that the inspection method or technique and frequency of inspection should be justified.
| |
| The staff notes that it has reviewed the technical adequacy of the LSTP and has found the conclusions of the LSTP to serve as an adequate basis for managing the aging effect of "cracking due to expansion caused by reaction from aggregates." The staff's review of the technical aspects of the LSTP is documented in its SE related to LAR 16
| |
| -03. The staff finds the applicant's "detection of aging effects" program element to be adequate because:
| |
| (1) The applicant's method for identifying the presence of ASR is the performance of visual inspections for characteristics of ASR at the concrete surface. The staff agrees that visual examinations are sufficient to detect ASR prior to it having any impact on structural function. In addition, in its November 2, 2012, response to RAI B.2.1.31
| |
| -5, the applicant stated that visual inspections will be used to monitor the progression of ASR, and will not be used to rule out its presence. The staff finds that using visual indications of ASR to identify its presence will adequately detect ASR prior to a loss of intended function. The program also conservatively assumes ASR to be a credible aging effect for all concrete structures on site.
| |
| (2) The AMP includes opportunistic or focused inspections of inaccessible areas. In addition, as stated in the applicant's June 30, 2015, response to RAI B.2.1.31a
| |
| -6(a), the applicant has performed several inspections of inaccessible areas and results to date have confirmed that the levels of ASR observed in inaccessible areas have been consistent with those observed in accessible areas. The applicant also stated that if a Tier 2 or Tier 3 ASR location is identified during an opportunistic or focused inspection of an inaccessible area, the re
| |
| -inspection would occur at the prescribed frequency and methods for that tier. During its May 1
| |
| -3, 2018, IP 71002 inspection, the staff confirmed that periodic maintenance protocols are being put into place to ensure that a focused inspection is performed during the five year inspection interval if no opportunistic inspection can be credited.
| |
| (3) ASR expansion progresses slowly; the relatively frequent 6
| |
| -month expansion monitoring period for the most severe ASR degradation locations is conservative, which provides Aging Management Review Results 3-234 reasonable assurance that a loss of intended function could be detected prior to the next scheduled inspection.
| |
| (4) ASR will be monitored for in
| |
| -plane and out
| |
| -of-plane expansion and the volumetric data will be considered. The staff finds that using all three indications is adequate because ASR expansion occurs in all directions. Using volumetric data to detect expansion as a whole and ensuring that the expansion levels are bounded by the volumetric expansion of the LSTP also serves to address small variations between the LSTP test specimens compared to Seabrook structures in through
| |
| -wall vs. in
| |
| -plane expansion.
| |
| (5) As discussed in the "operating experience" program element, the applicant committed (Commitment 66) to confirm the observation from the LSTP that expansion is initially similar in all directions but then as ASR progresses, preferentially expands in the through-thickness direction. The applicant will confirm this observation at least five years prior to the period of extended operation and every 10 years thereafter.
| |
| Based on its review of the application, as revised by letter dated May 18, 2018, and review of the applicant's response to RAIs, the staff confirmed that the "detection of aging effects" program element satisfies the criteria defined in SRP
| |
| -LR Section A.1.2.3.4; therefore, the staff finds it acceptable.
| |
| Monitoring and Trending. LRA Section B.2.1.31A states that the program will measure the progression of ASR in the in
| |
| -plane and through
| |
| -thickness directions using in
| |
| -plane measurements (CCI or embedded pins), out-of-plane measurements (snap
| |
| -ring borehole extensometers), and volumetric expansion assessments to apply the test results from the LSTP and trend data. The program will consider the rate at which a location is approaching the CCI and expansion limits and will use that information to take actions to ensure continued structural adequacy.
| |
| The staff reviewed the applicant's "monitoring and trending" program element against the criteria in SRP
| |
| -LR Section A.1.2.3.5, which state that this program element should describe the monitoring and trending activities and "how" the data collected are evaluated.
| |
| The staff finds the applicant's "monitoring and trending" program element to be adequate because: (1) The program will inspect all "Tier 3" (i.e., most severe) ASR locations and not a sample; therefore, considerations for sample selection representativeness are not needed, as discussed in RAI B.2.1.31A
| |
| -5(a3) and its response, dated December 3, 2015.
| |
| (2) The applicant stated in its May 15, 2014, response to RAI B.2.1.31A
| |
| -2 that the Tier 3 inspection frequency was established based on guidance provided in the FHWA's "Report on the Diagnosis, Prognosis, and Mitigation of Alkali
| |
| -Silica Reaction (ASR) in Transportation Structures," the Tier 2 frequency was determined to be an interim interval between Tier 1 and Tier 3, and current inspection results indicate that the Tier 2 interval has been adequate to monitor ASR progression. During its March 19
| |
| -22, 2018, onsite audit, the staff reviewed several years of inspection results to date and confirmed that this frequency is adequate to monitor ASR progression such that degradation can be detected prior to a loss of intended function (noting that ASR expansion in Tier 2 areas is not advanced). Since the ASR progression has been slow, the staff has reasonable assurance that inspection intervals are adequate to identify whether ASR expansion will Aging Management Review Results 3-235 reach tested levels prior to the next inspection. In addition, the applicant stated that it will review the rate at which a location is approaching the established limit and take action if the limit is anticipated to be exceeded prior to the next planned inspection.
| |
| (3) As noted in the February 25, 2015, responses to RAIs B.2.1.31A
| |
| -2(a) and B.2.1.31
| |
| -7, although the inspection intervals of Tier 2 and Tier 3 ASR
| |
| -affected areas currently specified in the ASR Monitoring Program may change based on trending of previous inspection results, the inspection interval will not exceed the maximum inspection interval of five years specified in the Structures Monitoring Program for components in a harsh environment. This is adequate because even if inspection frequencies are changed due to a lack of or very slow expansion, a (maximum) five
| |
| -year interval will be consistent with inspection guidelines contained in Chapter 6 of ACI 349.3R
| |
| -96 and GALL Report recommendations.
| |
| Based on its review of the application, as revised by letter dated May 18, 2018, and review of the applicant's response to RAIs, the staff confirmed that the "monitoring and trending" program element satisfies the criteria defined in SRP
| |
| -LR Section A.1.2.3.5; therefore, the staff finds it acceptable.
| |
| Acceptance Criteria. LRA Section B.2.1.31A states that any area with visual presence of ASR (as defined in Federal Highway Administration's FHWA
| |
| -HIF-12-022) and a cracking index (CI) of less than 0.5 mm/m in the vertical and horizontal direction is considered Tier 2 and is monitored qualitatively. Areas with CI greater than or equal to 0.5 mm/m in the vertical and horizontal direction or a CCI (average of the CI values in either direction) of 0.5 mm/m or above are also classified as Tier 2 but are monitored quantitatively (via CCI measurements) and trended. The LRA states that a CCI threshold of 0.5 mm/m for quantitative monitoring is used because individual crack widths smaller than 0.5 mm/m cannot be accurately measured and reliably repeated with standard visual inspection equipment.
| |
| For CCI greater than or equal to 1.0 mm/m, the LRA states that a structural evaluation and through-thickness expansion monitoring is required, and that the structural evaluation performed for the BDMP AMP (Section 3.0.3.3.7 of this SER) fulfills this requirement. For ASR
| |
| -affected structures within the scope of the ASR Monitoring Program AMP but not within the scope of the BDMP AMP, if a structural evaluation does not exist, one will be performed. If a structural evaluation has been performed, the program will verify that the in
| |
| -plane expansion included in the structural evaluation bounds the as
| |
| -found condition, or will update the existing evaluation to bound the as
| |
| -found condition and provide margin for future expansion. For Tier 3 areas, the LRA states that the acceptance criteria for structural evaluation were developed from the applicant's LSTP. Specific criteria for in
| |
| -plane and out
| |
| -of-plane expansion are in FP#101020 Section 2.1, and the criteria for volumetric expansion are in FP#101050 Appendix B. The staff reviewed the applicant's "acceptance criteria" program element against the criteria in SRP-LR Section A.1.2.3.6, which state that the acceptance criteria of the program and its basis should be described. The acceptance criteria should ensure that the intended functions are maintained consistent with all CLB design conditions during the period of extended operation.
| |
| The staff notes that it has reviewed the technical adequacy of the LSTP and has found that the conclusions of the LSTP establish an adequate basis for acceptance criteria for concrete degradation from cracking due to expansion from reaction with aggregates. The staff's review Aging Management Review Results 3-236 of the technical aspects of the LSTP is documented in the staff's SE related to LAR 16
| |
| -03. The staff finds the applicant's "acceptance criteria" program element to be adequate because:
| |
| (1) For ASR expansion only, the acceptance criteria used were determined from the testing of large-scale specimens comparable to Seabrook structures that were tested to the Seabrook design basis limits for the most critical limit states (the staff notes that all limit states were assessed and that this is discussed in revised report MPR 3727, which was submitted in the applicant's May 18, 2018 letter).
| |
| (2) The acceptance criterion of 1 mm/m as the point at which a structural evaluation is needed allows for the program to verify that in
| |
| -plane expansion is adequately bounded in the overall evaluation. This is acceptable because the ASR Monitoring Program AMP will provide input to the structural evaluations conducted under the BDMP AMP to ensure that in
| |
| -plane expansion is adequately accounted for with regards to the structure's ability to perform its intended function(s).
| |
| (3) The ultimate limits for expansion are based on the LSTP, from which the staff has determined (in its review of LAR 16
| |
| -03) that, up to the values tested in the program, there is no impact on structural intended function.
| |
| Based on its review of the application, as revised by letter dated May 18, 2018, the staff confirmed that the "acceptance review" program element satisfies the criteria defined in SRP
| |
| -LR Section A.1.2.3.6 and, therefore, the staff finds it acceptable.
| |
| Operating Experience. LRA Section B.2.1.31A summarizes operating experience related to the ASR Monitoring Program. The LRA states that, historically, the below-grade walls of Seabrook concrete structures have experienced groundwater infiltration. The LRA indicates that an evaluation was conducted in the 1990s to assess the effect of groundwater infiltration, which "concluded that there would be no deleterious effect, based on the design and placement of the concrete and on the non
| |
| -aggressive nature of the groundwater." Seasonal groundwater samples taken in 2009, to support the development of the LRA, indicated that the groundwater had become aggressive. The LRA further states that a comprehensive review of possible effects due to the aggressive nature of the groundwater was initiated, which showed the presence of ASR and reductions in compressive strength and elastic modulus of the affected concrete. The LRA states that an engineering evaluation concluded that the impacted structures were capable of performing their safety function but with reduced margin.
| |
| The LRA states that NextEra Energy will update the ASR Monitoring Program AMP for any new plant-specific or industry operating experience, including ongoing industry studies and research if applicable. The LRA also states that the applicant submitted a license amendment request in accordance with 10 CFR 50.90 to incorporate in the Seabrook current licensing basis a revised methodology related to ASR material properties and building deformation analysis for review and approval (LAR 16
| |
| -03). The staff's review of the LSTP and its conclusions, which are credited as the basis of the ASR Monitoring Program, are documented in the staff's SE related to LAR 16-03. The LRA discusses several opportunistic inspections of buried concrete and indicated that there have not been any observations to date where ASR degradation was not bounded by the conditions of accessible concrete. The applicant stated and the staff confirmed during its onsite audit that areas that were identified to have ASR meeting the limits of Tier 2 or Tier 3 were included in the periodic inspection for the corresponding Tier.
| |
| | |
| Aging Management Review Results 3-237 The LRA discusses several actions that the applicant plans to take to confirm that the expansion behavior observed in Seabrook structures is consistent with the observations from the LSTP.
| |
| The applicant stated that at least 5 years before the period of extended operation and every 10 years thereafter the applicant will periodically confirm expansion behavior by:
| |
| (1) Reviewing records for cores removed to date or since the last assessment to confirm that there is no mid
| |
| -plane cracking.
| |
| (2) Comparing in
| |
| -plane (x- and y-directions) expansion with through
| |
| -wall (z-direction) expansion observed on site against a plot of CCI to through
| |
| -wall expansion from the LSTP to confirm that the expansion initially is similar in all directions, but becomes preferential in the z
| |
| -direction.
| |
| (3) Comparing measured expansions to limits from the LSTP to check margin for future expansion.
| |
| In addition, the applicant stated that at least 5 years before the PEO (initial study) and 10 years thereafter (followup study), a study will be completed to corroborate modulus
| |
| -expansion correlation with plant data. In the study, for 20% of extensometer locations, the applicant will compare through
| |
| -wall expansion determined from the LSTP modulus-expansion correlation with through-wall extensometer measurements and the original elastic modulus reduction result used to initially determine through
| |
| -wall expansion to date at the time of extensometer installation. The applicant stated that a detailed explanation of the approach for validation of expansion behavior is provided in Report MPR
| |
| -4273 Revision 1, which was submitted to the NRC in a letter dated May 18, 2018.
| |
| The staff reviewed this information against the acceptance criteria in SRP
| |
| -LR Section A.1.2.3.10, which states that consideration of future plant
| |
| -specific and industry operating experience relating to AMPs should be discussed. The operating experience of AMPs that are existing programs, including past corrective actions resulting in program enhancements or additional programs, should also be considered. For new AMPs that have yet to be implemented, the SRP states that an applicant should commit to a review of future plant
| |
| -specific and industry operating experience for new programs to confirm their effectiveness.
| |
| The staff reviewed operating experience information in the application and during the March 1922, 2018, audit to determine whether the applicable aging effects and industry and plant
| |
| -specific operating experience were reviewed by the applicant. The staff finds the "operating experience" program element acceptable because:
| |
| (1) From its review of the LRA and onsite review of AMP basis documents, the corrective action program, and implementing procedures, the staff noted that the applicant's program appropriately identifies plant
| |
| -specific operating experience and has used that operating experience to make necessary adjustments to the program to ensure that it continues to manage ASR effects on structural functionality.
| |
| (2) The program will continue to monitor industry and plant
| |
| -specific operating experience, including relevant national and international research, and will modify the program as necessary.
| |
| (3) The applicant committed (Commitment 66) to verify expansion behavior of Seabroo k structures in comparison to expansion of the LSTP specimens; specifically, the observation that in
| |
| -plane expansion plateaus at lower levels of ASR expansion and that Aging Management Review Results 3-238 through-wall expansion dominates. This corroboration is significant because through
| |
| -wall expansion data obtained in the LSTP are credited as the basis for continued functionality of Seabrook structures.
| |
| (4) In its response to RAI B.2.1.31A
| |
| -A4-2 (dated October 3, 2017) the applicant revised Commitment 45 regarding corroboration of Seabrook structures expansion behavior (specifically, the modulus
| |
| -expansion correlation) to the LSTP, from examining three areas at one point in time to examining 20 percent of through
| |
| -wall locations once at 5 years prior to the period of extended operation and at 10 year intervals thereafter. The staff finds that the sample number and frequency provide for a meaningful validation prior to the period of extended operation and appropriate reevaluation during the period of extended operation.
| |
| Based on its audit and review of the application, and review of applicable RAI responses, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the scope of the program and that implementation of the program has resulted in the applicant taking appropriate corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10. UFSAR Supplement. LRA Section A.2.1.31A provides the UFSAR supplement for the ASR Monitoring Program. The staff reviewed this UFSAR supplement description of the program against the recommended description for this type of program as described in SRP
| |
| -LR Table 3.0-1. This guidance states that the program description should contain information associated with the bases for determining that aging effects will be managed during the period of extended operation.
| |
| The staff also noted that the applicant committed (Commitment 71) to implement the ASR Monitoring Program prior to the period of extended operation for managing the effects of aging for applicable components. The staff also noted that the applicant committed (Commitment83) to (1) install extensometers in all Tier 3 areas of two dimensionally reinforced structures to monitor expansion due to alkali
| |
| -silica reaction in the out
| |
| -of-plane direction; and (2) monitor expansion in the out
| |
| -of-plane direction upon installation of extensometers and continue on a six month frequency through the period of extended operation. The staff notes that the applicant has completed extensometer installation in applicable locations, and is monitoring through
| |
| -wall expansion on a s ix-month frequency; thus, this Commitment has been completed. The applicant also committed (Commitments 45 and 66) to periodic confirmation of expansion behavior. Specifically, at least 5 years prior to the period of extended operation and 10 years thereafter: (1) To verify that there is no mid
| |
| -plane cracking, the applicant will review records for cores removed to date or since the last assessment.
| |
| (2) To verify that expansion is initially similar in all directions but becomes preferential in the z-direction, the applicant will compare measured in
| |
| -plane expansion to through
| |
| -thickness expansion using a plot of through
| |
| -thickness expansion versus combined cracking index (CCI) as compared to the observations in the LSTP.
| |
| (3) To verify that expansion remains within the range observed in the LSTP, the applicant will compare measured in
| |
| -plane (x- and y-directions), out
| |
| -of-plane (z-direction), and Aging Management Review Results 3-239 volumetric expansions observed in Seabrook structures to the limits from the LSTP, to check margin for future expansion as it relates to structural capacity.
| |
| (4) To corroborate the modulus of elasticity to the expansion correlation used to determine expansion at the time of extensometer installation, the applicant will remove additional cores from 20 percent of the Tier 3 areas of Seabrook structures and compare to the correlation curve developed from LSTP observations.
| |
| The staff determined that the information in the UFSAR supplement, as amended by the commitments provided, is an adequate summary description of the program, as required by 10 CFR 54.21(d) and is, therefore, acceptable.
| |
| Conclusion. On the basis of its technical review of the applicant's ASRMP, the staff concludes that the applicant demonstrated that, through the use of this AMP, the effects of aging of concrete structures affected by ASR will be adequately managed so that the intended function(s) of the structures under consideration will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.3.7 Building Deformation Monitoring Program As documented in Seabrook Station, Unit No. 1
| |
| - Integrated Inspection Report 05000443/2015002 (ADAMS Accession No. ML15217A256), in the 2014/2015 timeframe, the applicant discovered operating experience in Seabrook structures affected by ASR, as described below, potentially attributable to ASR causing global bulk expansion of concrete. The report indicates that the applicant's evaluation of the degraded conditions confirmed that the identified deformation is due to bulk expansion from long term cumulative effects of ASR and strain associated with creep. In NRC Inspection Reports 05000443/2014003 (ADAMS Accession No. ML14212A458), 05000443/2014005 (ADAMS Accession No. ML15037A172), 05000443/2015002 (ADAMS Accession No. ML15217A256), and 05000443/2014009 (ADAMS Accession No. ML14349A751), the NRC staff noted the following indications:
| |
| * Relative deformation (differential movement) of the Containment Enclosure Building (CEB) indicated by changes in the 3
| |
| -inch seismic gaps or annulus gap between adjacent structures, damaged fire seals, misalignment of conduits/piping at penetrations or between adjacent structures, deformed flexible conduit couplings, bent small pipes/conduits and supports, etc.
| |
| * Discrete wide horizontal cracking, spalling, and doorway misalignments in the Residual Heat Removal (RH) and Containment Spray (CS) Vault.
| |
| * Cracking, displacements or other indications of structural conditions adverse to quality associated with the Fuel Storage Building (FSB).
| |
| In its June 30, 2015, submittal, the applicant stated that the ASRMP would include additional monitoring focused on identifying signs of the relative building deformation and included a new commitment to enhance the ASRMP to monitor for building displacement using laser targets and by taking gap measurements. The staff found this proposal insufficient because it was overly vague and did not appear to fully characterize the phenomena observed by the operating Aging Management Review Results 3-240 experience, thus it was not clear that the aging management activities would be sufficient to manage this aging degradation.
| |
| Therefore, by letter dated October 2, 2015, the NRC issued RAI B.2.1.31A
| |
| -8, requesting that the applicant address various issues regarding aging management of structures affected by global manifestations of ASR. The applicant's letter dated December 3, 2015 (ADAMS Accession No. ML15343A470), contained the applicant's response to RAI B.2.1.31A
| |
| -8, a revised ASRMP AMP and a revised list of commitments, including a revised Commitment 91 to address building deformation. At the time NextEra submitted its response, it had identified that gross relative deformation at the CEB was attributed to ASR, but had not definitively attributed ASR to observed operating experience (macro cracking) in other structures.
| |
| The staff determined that it did not have sufficient information regarding aging management for building deformation caused by ASR and also did not have a clear understanding of how the results of the LSTP would correlate to Seabrook structures. The staff determined the need to request additional information, and NextEra and the staff agreed to conduct a public meeting to discuss the staff's concerns. The meeting was held on April 28, 2016 (ADAMS Accession No. ML16109A004). During the meeting, the applicant stated that it would submit a supplement to the previous ASRMP, and subsequently did so by letter dated August 9, 2016 (ADAMS Accession No. ML16224B079).
| |
| The applicant's August 9, 2016, letter included two aging management programs, the ASR Monitoring Program (which was an update to the program submitted in 2012 and amended in 2015) and the Building Deformation Monitoring Program (BDMP), an additional plant
| |
| -specific program to address the effects of building deformation caused primarily by ASR. The applicant also submitted LAR 16
| |
| -03 dated August 1, 2016 (ADAMS Accession No. ML16216A240), and LAR supplement dated September 30, 2016 (ADAMS Accession No.ML16279A048).
| |
| LAR 16-03 requested to amend the Seabrook CLB to add a method for evaluating ASR
| |
| -affected structures at Seabrook; it also forms a technical basis for the ASR
| |
| -related AMPs for license renewal. This SER section addresses the staff's evaluation of aging management aspects of building deformation for the period of extended operation as part of the staff's review of the LRA; the staff's review of the adequacy of the technical bases supporting the AMPs, which are also applicable to the current licensing basis, is documented in the staff's SE related to LAR 1603. The staff evaluation of the plant
| |
| -specific ASRMP is documented in SER Section 3.0.3.3.6.
| |
| Summary of Technical Information in the Application. LRA Section B.2.1.31B states that the BDMP is a new plant
| |
| -specific program being implemented under the existing Maintenance Rule Structures Monitoring Program. The LRA states that building deformation is an aging mechanism that may occur as a result of other aging effects of concrete. The LRA also states that building deformation is primarily a result of ASR (described in LRA Section B.2.1.31A) but can also result from swelling, creep, and shrinkage. The LRA further states that building deformation can cause components within the structures to move such that their intended functions may be impacted.
| |
| The program uses visual inspections and cracking measurements from the Structures Monitoring Program and ASRMP to identify buildings experiencing deformation. The extent of surface cracking and field observations serve as input into an analytical model to determine the extent of deformation, threshold monitoring parameters and acceptance (threshold) limits, and Aging Management Review Results 3-241 frequency of required inspections. The program performs structural evaluations on buildings and components affected by deformation as necessary to validate structural performance against the design basis and to ensure that the structural function is maintained. The LRA states that these evaluations also consider the impact to functionality of affected systems and components against their design bases to determine whether corrective actions are needed. The program credits a Methodology Document as the procedural basis. The Methodology Document was submitted to the NRC by letter dated December 11, 2017 (ADAMS Accession No. ML17345A641), under LAR 16
| |
| -03. Evaluations performed in accordance with the Methodology Document are credited for aging management. The staff's detailed review of the technical aspects of the Methodology Document is documented in the SE related to LAR 16
| |
| -03. The August 9, 2016, LRA Section B.2.1.31B was subsequently revised by letters dated December 23, 2016, November 3, 2017, and May 18, 2018 (ADAMS Accession Nos. ML16362A283, ML17307A027, and ML18141A785, respectively).
| |
| Staff Evaluation. In support of its review of the BDMP, the NRC staff conducted several onsite audits. During its audits, the staff reviewed the applicant's BDMP against the requirements of 10 CFR Part 54; and guidance provided in SRP
| |
| -LR Appendix A.1, "Aging Management Review-Generic" and the GALL Report, to confirm that the AMP will adequately manage the effects of aging for structures affected by ASR and/or building deformation. The table below lists the audit dates, locations, and documentation:
| |
| Dates of Audit Location Audit Report ADAMS Accession No.
| |
| October 25
| |
| -27, 2016 Seabrook Station ML16333A247 March 19-22, 2018 Seabrook Station ML18135A046 During its review, the staff required several RAIs to address its questions related to the applicant's proposal to manage the effects of ASR and/or building deformation on structures' intended functions. As the applicant continued to evaluate the staff's questions, there were several revisions to the BDMP AMP. Unless otherwise noted, the staff's evaluation relates to the latest version of the BDMP submitted by letter dated May 18, 2018. Previous versions of the AMP and prior RAIs are only discussed as necessary to support the staff's conclusions. A summary of the RAIs, the RAI responses, and supplemental submittals are discussed briefly below, followed by the staff's evaluation of each of the program elements in the BDMP dated May 18, 2018.
| |
| * RAI B.2.1.31 B-B1 and -B2 issued by letter dated December 12, 2016: RAI B.2.1.31B
| |
| -B1 requested information on why the list of structures included in the scope of the ASR Monitoring Program and the BDMP was not consistent between the programs. RAI B.2.1.31B-B2 requested that for each structure in the scope of the program, provide a list of parameters monitored and their monitoring method(s); or provide a comprehensive discussion of the processes and procedures for determining the parameters to monitor and monitoring method(s), in a manner that would demonstrate repeatability of the process.
| |
| | |
| Aging Management Review Results 3-242
| |
| * RAI B.2.1.31B
| |
| -B1 and -B2 responses provided by letter dated December 23, 2016: In the RAI B.2.1.31B
| |
| -B1 response, the applicant added the Intake and Discharge Transition Structures to the scope of the program. The applicant explained that Non-Category 1 structures including yard structures, with the exception of Intake and Discharge Transition structures, are not included in the scope of the program due to not being expected to be susceptible to deformation based on configuration. In the RAI B.2.1.31B-B2 response, the applicant provided a general overview of the methodology used to determine parameters monitored, but it did not demonstrate a repeatable and specific methodology for use to define parameters monitored for any structure.
| |
| * RAI B.2.1.31B
| |
| -B2-1 (Followup to RAI B.2.1.31B
| |
| -B2) issued by letter dated March 16, 2017: Stated that the staff did not find the applicant's methodology to be repeatable, and could not necessarily be applied consistently. Staff requested that since the general methodology could not be verified to reliably determine the parameters monitored, that the applicant provide these parameters for each structure and demonstrate the capability of the parameters for detecting the presence and extent of aging effects. A public meeting was held on May 9, 2017, to discuss the staff's concerns (ADAMS Accession No. ML17137A029).
| |
| * By letter dated November 3, 2017, the applicant submitted a revised ASRMP. By letter dated December 11, 2017, the applicant submitted a Methodology Document that the applicant stated serves as a procedural basis for the BDMP. The staff performed an onsite audit March 19
| |
| -22, 2018, to review the applicant's submittal (ADAMS Accession No. ML18135A046).
| |
| The staff reviewed program elements one through six, and ten, of the applicant's program against the acceptance criteria for the corresponding elements as stated in SRP
| |
| -LR Section A.1.2.3. The staff's review focused on how the applicant's program manages building deformation through the effective incorporation of these program elements. The staff verified that program elements seven through nine, "corrective actions," "confirmation process," and "administrative controls," were consistent with the guidance in SRP
| |
| -LR Appendix A.1 during the audit conducted on March 19
| |
| -22, 2018; the staff also noted during its audit that these program elements are being effectively implemented. The staff's evaluation of program elements seven through nine is documented in SER Section 3.0.4. As stated earlier in this section, the licensee requested (LAR 16
| |
| -03) to amend the Seabrook CLB to account for ASR. In its review of LAR 16-03, the staff assessed the technical adequacy of the applicant's LSTP, which is also credited as a technical basis for the BDMP. The staff's review is documented in its SE related to LAR 16-03 (ADAMS Accession Nos. ML18204A282 (proprietary), ML18204A291 (nonproprietary)). Therefore, the adequacy of the testing methodology and the conclusions from the LSTP will not be discussed in this SER.
| |
| Scope of Program. LRA Section B.2.1.31B states that the scope of the program includes concrete structures within the scope of the Structures Monitoring Program and the ASME Section XI, Subsection IWL Program. The program proposes to manage the aging effect of building deformation, including due to expansion from reaction with aggregates, during the period of extended operation. The LRA lists the specific Seismic Category 1 and Non
| |
| -Category 1 structures included in the scope of license renewal.
| |
| The staff reviewed the applicant's "scope of program" program element against the criteria in SRP-LR Section A.1.2.3.1, which state that the scope of the program should include the specific Aging Management Review Results 3-243 structures and components, the aging of which the program manages. During an onsite audit, the staff verified that concrete structures within the scope of license renewal, and expected t o be susceptible to effects of deformation due to ASR (as clarified in the RAI B.2.31B
| |
| -B1 response dated December 23, 2016), are included in the BDMP.
| |
| The staff finds the applicant's "scope of program" program element to be adequate because the LRA clearly identifies all concrete structures within the scope of the program and the staff confirmed that all concrete structures within the scope of license renewal, and expected to be susceptible to deformation aging effects, are included in the AMP.
| |
| Based on its review of the application as documented in a letter dated May 18, 2018, the staff confirmed that the "scope of program" program element satisfies the criteria defined in SRP
| |
| -LR Section A.1.2.3.1; therefore, the staff finds it acceptable.
| |
| Preventive Actions. LRA Section B.2.1.31B states that the BDMP is a monitoring only program and does not rely on preventive actions. The staff reviewed the applicant's "preventive actions" program element against the criteria in SRP
| |
| -LR Section A.1.2.3.2, which state that some condition monitoring programs do not rely on preventive actions. However, SRP
| |
| -LR Section A.1.2.3.2 also states that in cases for which the condition monitoring programs may rely on preventive actions, the preventive activities should be specified. The staff finds the applicant's "preventive actions" program element to be adequate because the BDMP is a condition monitoring program that does not rely on preventive actions or mitigation measures and, therefore, preventive or mitigation measures need not be specified within this program element.
| |
| Based on its review of the application as documented in a letter dated May 18, 2018, the staff confirmed that the "preventive actions" program element satisfies the criteria defined in SRP
| |
| -LR Section A.1.2.3.2; therefore, the staff finds it acceptable.
| |
| Parameters Monitored or Inspected. LRA Section B.2.1.31B states that a Methodology Document (FP# 101196) describes a process in which ASR
| |
| -affected structures are initially screened for deformation and analyzed to assess the effects on structures for the self
| |
| -straining loads from ASR expansion, creep, shrinkage, and swelling. The Methodology Document was submitted to the NRC by letter dated December 11, 2017 (ADAMS Accession No. ML17345A641), under LAR 16
| |
| -03, and provides a detailed process for structural analysis and determination of parameters to monitor and threshold limits for each structure. The LRA provides an overview of the procedures in the Methodology Document.
| |
| The LRA states that each stage of the process (Stage One, Stage Two, and Stage Three) has increasing levels of rigor in that more advanced analysis techniques are used for increasing stages. The LRA states (and the Methodology Document details) that the specific locations where ASR exists in each structure, and the critical areas where the margin to licensing basis structural design code and design basis acceptance criteria are most limiting, influence the locations and types of measurements that are used to monitor each structure. The LRA further states that monitoring parameters, locations, frequencies, administrative limits, and threshold limits for each structure are determined based on results of the structure
| |
| -specific analysis and documented in the associated structural calculation.
| |
| | |
| Aging Management Review Results 3-244 The parameters monitored for structures are field observations (qualitative) and measurements (quantitative) that can be used to quantify ASR loads applied to each structure, which typically include (as applicable): cracking suspect of ASR (visual), cracking not suspect of ASR (visual), other structural or material distress (visual), crack index, in
| |
| -plane strain rate (using removable strain gage), through
| |
| -thickness expansion (for areas installed with extensometers), through
| |
| -thickness strain rate (extensometer), individual crack widths/lengths (instrument or tools to measure crack width changes, such as crack comparator, crack gages, extensometers, invar wires), seismic isolation joints (quantitative measurements), structure dimensions (quantitative measurements), and equipment/conduit offsets (quantitative measurement or visual observation).
| |
| The LRA states that four criteria are used to determine the initial stage of analysis required to determine the monitoring parameters:
| |
| (1) structures with simple geometry that permits structural analysis using closed
| |
| -form solutions and/or simple finite element models (2) structures with localized ASR expansion, or ASR expansion affecting the structure as a whole but with only minor indications of distress (3) structures with an apparent robust original design leading to a reasonable amount of margin to accommodate ASR demands (4) structures that do not exhibit significant signs of distress A Stage One analysis is a "Susceptibility Screening Evaluation," applicable to structures meeting all four criteria listed above. The LRA states that this category of evaluation applies to structures with minimal amounts of deformation that do not affect the structural capacity as determined in the original design analysis. For structures meeting two or three of the above criteria, a Stage Two "Analytical Evaluation" is performed. The LRA states that this category applies to structures with elevated levels of deformation that are shown to be acceptable using finite element analysis to calculate ASR loads but still meeting the original design basis requirements when ASR effects are included. For structures that can only meet one or none of the above criteria, a Stage Three "Detailed Evaluation" is performed. The LRA states that this category applies to structures with significant deformation that are analyzed and shown to meet the requirements of the code of record using the methods described in the Methodology Document. The LRA states that these analyses determine the parameters monitored or inspected for each structure, and that the program monitors each parameter against determined "threshold" limits in accordance with the licensing basis. Stage One, Two, and Three structures are monitored on a 36
| |
| -month, 18-month, and 6-month basis, respectively.
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| For components impacted by structural deformation, the LRA states that condition walkdowns, looking for specific listed features (e.g., distorted or misaligned components, gaps or tears in seals, crimped tubing, bent bolts, cracked welds), are performed with a focus on safety
| |
| -related components such as pumps, valves, conduits, and piping. The effects of deformation on plant equipment and seismic gaps will be managed through the corrective action program based on input from the Structures Monitoring Program to be dispositioned for impact on structures. Additionally, the LRA states that these inspections are in addition to installed monitoring elements such as strain measurements and measurements of the relative deformation between structures. These measurements will be performed at a frequency that ensures functionality of the affected components is not lost prior to the next inspection interval.
| |
| | |
| Aging Management Review Results 3-245 The staff reviewed the applicant's "parameters monitored or inspected" program element against the criteria in SRP
| |
| -LR Section A.1.2.3.3, which state that the program element should identify the aging effects that the program manages and provide a link between the parameters being monitored and how monitoring those parameters will ensure adequate aging management. SRP
| |
| -LR Section A.1.2.3.3 also states that, for condition monitoring programs, the parameter monitored or inspected should be capable of detecting the presence and extent of aging effects.
| |
| The staff finds the applicant's "parameters monitored or inspected" program element to be adequate because:
| |
| (1) The program uses visual inspections, in addition to quantitative and instrument measurements depending on the parameter.
| |
| (2) The staff reviewed the Methodology Document and determined that it is robust, with sufficient detail such that it is repeatable for any structure. The Methodology Document procedures can be used to reliably determine parameters to be monitored or inspected for an individual structure (the staff's detailed review of the Methodology Document is documented in its SE associated with LAR 16
| |
| -03). (3) The program uses structure
| |
| -specific analyses that are based on structure design bases and actual observed conditions and measurements to determine monitoring parameters and limits.
| |
| (4) The list of parameters is sufficiently complete to monitor typical features that can be observed to indicate building deformation is occurring or progressing in structures.
| |
| (5) The "Staged" approach for level of detail is reasonable in that structures more susceptible to building deformation potentially affecting structure intended function(s) receive increasingly detailed evaluation.
| |
| (6) Structure-specific limits are established for each parameter and are monitored to maintain within those threshold limits. (7) During its March 19
| |
| -22, 2018, audit the staff reviewed a sample of Stage One, Stage Two, and Stage Three structures and verified that the analyses yielded appropriate parameters monitored, and that these parameters and associated limits are implemented in the Structures Monitoring Program procedure for each structure and specific area of monitoring.
| |
| (8) The program includes inspection parameters for components that may be impacted by structural deformation.
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| Based on its review of the application, as revised by letter dated May 18, 2018, and review of the applicant's responses to RAIs, the staff confirmed that the "parameters monitored or inspected" program element satisfies the criteria defined in SRP
| |
| -LR Section A.1.2.3.3; therefore, the staff finds it acceptable.
| |
| Detection of Aging Effects. LRA Section B.2.1.31B states that baseline walkdowns are performed to identify the potential effects caused by building deformation. The results of the baseline walk downs are used to determine the key assumptions in the structural analysis. The recommended inspection frequencies for subsequent monitoring are defined in the Methodology Document and in program element "parameters monitored" in the LRA. The frequencies listed Aging Management Review Results 3-246 in that section are 36 months for Stage One, 18 months for Stage Two, and six months for Stage Three. The LRA notes that those inspection frequencies will be applied in locations where symptoms of deformation are identified; otherwise, the inspection frequency will follow the requirements of the Structures Monitoring Program. The staff notes that LRA Section B.2.1.31 states that for structures in harsh environments (defined in Section B.2.1.31), the inspection is conducted on a five year basis. The LRA states that the inspections are completed by qualified individuals at a frequency determined by the characteristics of the environment in which the structure is found. The LRA further states that the program will consider the rate of expansion and building deformation and will take appropriate action if the structural integrity of the structure and associated components are projected to be lost prior to the next inspection. The LRA also notes that walkdowns and visual inspections will be conducted of components that may be impacted by building deformation.
| |
| The staff reviewed the applicant's "detection of aging effects" program element against the criteria in SRP
| |
| -LR Section A.1.2.3.4, which state that the program element should address how the program would detect the occurrence of age
| |
| -related degradation, prior to a loss of intended function. This element should also discuss "when," "where," and "how" data will be collected. For condition monitoring programs, the SRP
| |
| -LR states that the inspection method or technique and frequency of inspection should be justified.
| |
| The staff finds the applicant's "detection of aging effects" program element to be adequate because: (1) The methods used to monitor each parameter, as described in the "parameters monitored or inspected" program element (i.e., qualitative visual examinations, quantitative crack index measurements, strain gage measurements, through
| |
| -thickness extensometer measurements, quantitative crack width measurements, quantitative seismic gap measurements, quantitative measurement of structural dimensions) are adequate to detect building deformations and movements.
| |
| (2) The frequencies proposed in the program are appropriate. As the staff observed in its March 19-22, 2018, audit, building deformations observed on site have progressed slowly. For Stage One structures with minimal deformation that do not affect the structural capacity as defined in the original design analysis, 36 months is adequate and the threshold for the most frequent 6
| |
| -month expansion monitoring period is conservative. In addition, the program will consider the rate of expansion to the next inspection to ensure that structures and components will not lose functionality prior to the next scheduled inspection. The staff observed during its March 19
| |
| -22, 2018, audit that the program is currently in place and that the applicant is taking measurements at the stated intervals. This provides reasonable assurance that the data will be available to determine whether a loss of intended function would occur prior to the next scheduled inspection.
| |
| (3) Inspections are completed by qualified individuals, in accordance with GALL Report recommendations.
| |
| (4) Monitoring areas are based on critical locations, as determined by the individual structure-specific evaluation, and as discussed in the Methodology Document Based on its review of the application, as revised by letter dated May 18, 2018, and review of the applicant's responses to RAIs, the staff confirmed that the "detection of aging effects" Aging Management Review Results 3-247 program element satisfies the criteria defined in SRP
| |
| -LR Section A.1.2.3.4; therefore, the staff finds it acceptable.
| |
| Monitoring and Trending. LRA Section B.2.1.31B states that once inspection frequencies are determined, visual inspections will be used to monitor and trend future building deformation. Any new indications of building deformation will be placed in the corrective action program and evaluations will be performed to determine if inspection frequencies should be changed to ensure future effects of degradation are identified prior to loss of intended function.
| |
| The staff reviewed the applicant's "monitoring and trending" program element against the criteria in SRP
| |
| -LR Section A.1.2.3.5, which state that this program element should describe the monitoring and trending activities and "how" the data collected are evaluated.
| |
| The staff finds the applicant's "monitoring and trending" program element to be adequate because:
| |
| (1) The features of building deformation will be monitored using instruments that are capable of producing repeatable measurements such that building deformation can be adequately trended.
| |
| (2) The data collected will be compared to the threshold value acceptance criteria (which are developed via a structural evaluation) for each area monitored to ensure that measured values are below the threshold values. In addition, the applicant stated that it will review the rate at which a location is approaching the established limit and take action if the limit is anticipated to be exceeded prior to the next planned inspection.
| |
| (3) The "parameters monitored or inspected" program element stated the interval for recording monitoring elements for deformation for each structure can be increased to the interval in the next lower stage if no change in measurements are observed for 3 years. Stage One structures that have shown no change in deformation for 10 years may increase the inspection interval to once every 5 years. Structures that show no evidence of building deformation will continue to be inspected with a frequency as established by the Structures Monitoring Program. This is adequate because even if inspection frequencies are changed due to lack of or very slow expansion, a (maximum) five
| |
| -year interval will be consistent with inspection guidelines contained in Chapter 6 of ACI 349.3R-96 and GALL Report recommendations.
| |
| Based on its review of the application, as revised by letter dated May 18, 2018, and review of the applicant's responses to RAIs, the staff confirmed that the "monitoring and trending" program element satisfies the criteria defined in SRP
| |
| -LR Section A.1.2.3.5; therefore, the staff finds it acceptable.
| |
| Acceptance Criteria. LRA Section B.2.1.31B states that as described in the Methodology Document, the threshold factor is the design margin expressed as the amount by which ASR loads can increase beyond currently measured values that are used in the calculations such that the structure or structural component will still meet the allowable limits of the code. Threshold factor is an outcome of the evaluation as opposed to an input to the analysis methodology approach. A unique threshold factor is calculated for each building based on the available margin, and is used to establish threshold limits for structural monitoring parameters.
| |
| | |
| Aging Management Review Results 3-248 The LRA states that an administrative limit of 97 percent of the threshold limit is set for all stages in addition to reductions of 90 percent and 95 percent for Stages One and Two threshold limits, respectively. The additional three percent margin plus the reduction to threshold factors for Stages One and Two analyses provide time to perform additional inspections to confirm that the limits are being approached and to initiate corrective actions. When the administrative limits are reached, further structural evaluation in accordance with the Methodology Document will be performed and corrective actions (e.g., re
| |
| -evaluate structure, structural modification, more frequent monitoring) taken as necessary.
| |
| The LRA discusses chemical prestressing due to ASR and the potential for rebar strain. The LRA states that the codes of record combined with the analytical approaches and acceptance criteria described in the Methodology Document ensure that structure behavior remains elastic (under service conditions), as long as ASR
| |
| -affected structures are monitored against the threshold limits.
| |
| The staff reviewed the applicant's "acceptance criteria" program element against the criteria in SRP-LR Section A.1.2.3.6, which state that the acceptance criteria of the program and its basis should be described. The acceptance criteria should ensure that the intended functions are maintained consistent with all CLB design conditions during the period of extended operation.
| |
| The staff finds the applicant's "acceptance criteria" program element to be adequate because:
| |
| (1) The staff determined that the Methodology Document, which is the procedural document used to develop acceptance criteria for ASR
| |
| -affected structures, is an adequate approach that yields acceptance criteria for each parameter monitored for each structure (the staff's detailed review of the Methodology Document is documented in its SE related to LAR 16
| |
| -03). (2) The acceptance criteria are based on structure
| |
| -specific analysis and structural evaluations that take into account the design basis for each structure.
| |
| (3) There are administrative limits that trigger a structural re
| |
| -evaluation or other corrective action prior to loss of a structure's intended function.
| |
| (4) The potential for ASR
| |
| -induced rebar strains has been taken into account in the structural evaluations in accordance with the Methodology Document, and rebar will remain elastic under service conditions as long as threshold limits and ASR expansion limits have not been exceeded.
| |
| Based on its review of the application, as revised by letter dated May 18, 2018, the staff confirmed that the "acceptance review" program element satisfies the criteria defined in SRP
| |
| -LR Section A.1.2.3.5 and, therefore, the staff finds it acceptable.
| |
| Operating Experience. LRA Section B.2.1.31B discusses operating experience related to building deformation. Specifically:
| |
| * Building Deformation
| |
| - Containment Enclosure Building (CEB): In late 2014, a walkdown was performed to investigate a concern from the staff that water was leaking into the Mechanical Penetration area through building seals. The seal was found torn and it was determined that the tear occurred because of relative movement between the Containment Building and the CEB. It was determined through measurements and Aging Management Review Results 3-249 visual assessments that the CEB experienced outward radial deformation caused by internal in
| |
| -plane expansion (strain) in the concrete produced by ASR in the CEB and also in the backfill concrete. The applicant's evaluation of the CEB identified different symptoms of building deformation and, as a result, walkdowns were performed to identify these symptoms that may have been missed prior to this discovery.
| |
| * Building Deformation
| |
| - Residual Heat Removal (RH) Equipment Vault and Fuel Storage Building (FSB): Expansion resulting in building deformation has been observed in the RH Equipment Vault and FSB. These have been determined to be Stage Three structures. As a result of identified observations, additional monitoring has been established in the RH Equipment Vault (invar rod extensometers, crack gages), and enhanced use of laser measurements is being evaluated for use in the FSB.
| |
| * Building Deformation
| |
| - "B" Electrical Tunnel: The applicant evaluated the "B" electrical tunnel using its Methodology Document. Following the methodology, the governing failure mode is out
| |
| -of-plane shear, however, there are no indications of flexural cracking. As a result, this wall is subject to an enhanced monitoring frequency to detect signs of flexural cracking.
| |
| * Building Deformation
| |
| - Containment Enclosure Ventilation Area (CEVA) North Wall: The CEVA structure exhibits extensive cracking and out
| |
| -of-plane deformation that is attributed to expansion of the concrete fill behind it. Enhanced monitoring is in effect and plans are in place to perform a structural retrofit.
| |
| * Building Deformation
| |
| - Safety-Related Electrical Manholes: Several safety
| |
| -related electrical manholes were analyzed using the Methodology Document and shown not to meet code criteria. The applicant determined that eliminating the possibility of surcharge loading was necessary and will be controlled through physical and administrative controls.
| |
| The LRA also includes additional plant
| |
| -specific operating experience related to seismic isolation gaps less than nominal value, misalignment of ducts, and deformed and misaligned flexible couplings.
| |
| The LRA states that NextEra Energy will update the AMP for any new plant
| |
| -specific or industry operating experience, including ongoing industry studies and research if applicable. The LRA also states that the applicant submitted an LAR in accordance with 10 CFR 50.90 to incorporate in the Seabrook CLB a revised methodology related to ASR material properties and building deformation analysis (LAR 16
| |
| -03). The staff reviewed this information against the acceptance criteria in SRP
| |
| -LR Section A.1.2.3.10, which state that consideration of future plant
| |
| -specific and industry operating experience relating to AMPs should be discussed. The operating experience of AMPs that are existing programs, including past corrective actions resulting in program enhancements or additional programs, should also be considered. For new AMPs that have yet to be implemented, the SRP states that an applicant should commit to a review of future plant
| |
| -specific and industry operating experience to confirm their effectiveness.
| |
| The staff reviewed operating experience information in the application and during the March 19-22, 2018, audit to determine if the applicable aging effects and industry and plant
| |
| -
| |
| Aging Management Review Results 3-250 specific operating experience were reviewed by the applicant. The staff finds the "operating experience" program element acceptable because:
| |
| (1) Based on its review of the LRA, its onsite review of AMP basis documents, and the corrective action program and implementing procedures reviewed on site, the staff noted that the applicant's program appropriately identifies plant
| |
| -specific operating experience and has used that operating experience to make necessary adjustments to the program to ensure that it continues to manage ASR effects on structural functionality.
| |
| (2) The program will continue to monitor industry and plant
| |
| -specific operating experience, including relevant national and international research, and will modify the program as necessary.
| |
| Based on its audit and review of the application, the staff finds that operating experience related to the applicant's program demonstrates that it can adequately manage the effects of ASR
| |
| -related building deformation on SSCs within the scope of the program, and that implementation of the program has resulted in the applicant taking appropriate corrective actions. The staff confirmed that the "operating experience" program element satisfies the criterion in SRP
| |
| -LR Section A.1.2.3.10.
| |
| UFSAR Supplement. LRA Section A.2.1.31B provides the UFSAR supplement for the BDMP. The staff reviewed this UFSAR supplement description of the program against the guidance for a plant-specific program in SRP
| |
| -LR Table 3.0
| |
| -1. This guidance states that the program description should contain information associated with the bases for determining that aging effects will be managed during the period of extended operation. In addition, Commitment 71 states that the applicant will implement the BDMP prior to the period of extended operation. Commitment 91 states that by March 15, 2020, the applicant will:
| |
| (1) Enhance the Structures Monitoring Program to require structural evaluations be performed on buildings and components affected by deformation as necessary to ensure that the structural function is maintained.
| |
| (2) Enhance the BDMP AMP to include additional parameters to be monitored based on the results of the CEB Root Cause analysis, structural evaluations, and walkdowns. Additional parameters monitored will include alignment of ducting, conduit and piping, seal integrity, laser target measurements, key seismic gap measurements, and additional instrumentation.
| |
| (3) Develop a design standard to implement the BDMP program element 3 (Parameters Monitored/Inspected). The design standard will clarify the deformation evaluation process and provide an auditable format to assess it. The design standard will include steps for each of the three evaluation stages that include parameters monitored, basis for why the parameter is monitored, and conditions that prompt actions for the subsequent step.
| |
| The staff noted that although the applicant stated that these actions would be completed by March 15, 2020, these activities have already been implemented. The detailed review of Numbers (1) and (3) is documented in the staff's SE related to LAR 16
| |
| -03, and the detailed review of Number (2) is documented in the staff's review of program elements (3) and (4) above.
| |
| Aging Management Review Results 3-251 The staff determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d) and is, therefore, acceptable.
| |
| Conclusion. On the basis of its technical review of the applicant's BDMP, the staff concludes that the applicant demonstrated that, through the use of this AMP, the effects of aging of concrete structures and other components affected primarily by ASR-related building deformation will be adequately managed so that the intended function(s) of the structures under consideration will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| 3.0.3.4 Aging Management Program Related to Interim Staff Guidance Issuance 3.0.3.4.1 Aging Management Related to Loss of Coating Integrity for Internal Coatings on In
| |
| -Scope Mechanical SSCs Program Summary of Technical Information in the Application. Based on reviews of LRAs and industry operating experience, the staff identified an issue concerning loss of coating integrity of internal coatings of piping, piping components, heat exchangers, and tanks. In addition, the staff issued LR-ISG-2013-01, "Aging Management of Loss of Coating or Lining Integrity for Internal Coatings/Linings on I n-Scope Piping, Piping Components, Heat Exchangers, and Tanks," that contains a new AMP, GALL Report AMP XI.M42, "Internal Coatings/Linings for In
| |
| -Scope Piping, Piping Components, Heat Exchangers, and Tanks," and AMR items. By letter dated March 5, 2014, the applicant amended its LRA to address managing loss of coating integrity associated with coatings installed on the internal surfaces of in
| |
| -scope piping, piping components, heat exchangers, and tanks.
| |
| The applicant augmented (enhanced) the following programs: LRA Sections B.2.1.11, Open
| |
| -Cycle Cooling Water System; B.2.1.16, Fire Water System; B.2.1.18, Fuel Oil Chemistry; and B.2.1.25, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Programs, to include the requirements listed below.
| |
| The staff noted that the applicant did not include spalling and rusting in its list of parameters to be inspected. However, the applicant revised the above
| |
| -referenced programs to include a chart titled "Inspection Intervals for Internal Service Level." The staff finds the inspection method and parameters monitored acceptable because they are consistent with the recommendations associated with inspection methods and parameters monitored in AMP XI.M42, and periodic visual examinations are capable of detecting loss of coating integrity by inspecting for indications such as blistering, cracking, flaking, spalling, and rusting.
| |
| Staff Evaluation. The staff's evaluation of the applicant's LRA amendment dated March 5, 2014, and response to RAIs, in accordance with the recommendations in LR
| |
| -ISG-2013-01, follows.
| |
| Definition of Service Level 3 (augmented) internal coatings. The applicant defined Service Level 3 (augmented) coatings (hereinafter referred to as "coatings") as:
| |
| All coatings applied to the internal surfaces of an in
| |
| -scope component if its degradation could prevent satisfactory accomplishment of any of the functions Aging Management Review Results 3-252 identified under 10 CFR 54.4 (a)(1), (a)(2), or (a)(3). Service Level III (augmented) coatings are those: (a) Used in areas outside of the reactor containment whose failure could adversely affect the safety function of a safety
| |
| -related SSC or, (b) Applied to the internal surfaces of in
| |
| -scope components and whose failure could prevent satisfactory accomplishment of any of the functions identified under 10 CFR 54.4 (a)(3).
| |
| The applicant also stated that coatings include inorganic and organic paints, coatings and linings, and concrete surfacers (i.e., a coating).
| |
| The staff noted that the applicant's use of the term "Service Level III (augmented) coatings" is consistent with the terminology used in the draft LR
| |
| -ISG-2013-01. The staff also noted that the term "areas outside of the reactor containment" could exclude coatings installed on the internal surfaces of in
| |
| -scope piping, piping components, heat exchangers, and tanks that are located in the containment. By letter dated November 18, 2014, the staff issued RAI 3.0.3.4
| |
| -1, requesting that the applicant state whether there are any internally coated in
| |
| -scope piping, piping components, heat exchangers, or tanks that are located in the containment, and if there are, how will loss of coating integrity be managed as an aging effect for these components.
| |
| The applicant replied to this RAI on March 9, 2015; however, subsequent to a conference call conducted with the applicant on May 5, 2015, by letter dated May 19, 2015, the applicant revised its response to state that the RCP upper bearing coolers and motor air coolers are internally coated with a rust
| |
| -inhibiting paint. Each of the trains of primary component cooling water to these coolers has similar chemistry parameters, flows, and temperatures. The coatings are the same in each cooler. In addition, the coolers are not subject to turbulent flow conditions. All four RCP motors are refurbished and replaced over a 6
| |
| -year period, followed by a 3-year period when no replacements are conducted. During each motor refurbishment, the internal surfaces of the coolers are recoated. The Internal Surfaces in Miscellaneous Piping and Ducting Components Program was revised to state the above and a new enhancement, Enhancement No. 3, and Commitment 89 were added to the program. The enhancement and commitment state that Service Level 3 coating requirements will be incorporated into the RCP motor refurbishment procedure, and all four RCP motors will be refurbished using these requirements prior to entering the period of extended operation. The applicant stated that its Service Level 3 coating qualification requirements are consistent with LR
| |
| -ISG-2013-01. The applicant also stated that there are no other in-scope internally coated components in the containment.
| |
| The staff finds the applicant's response acceptable because the only i n-scope components with internal coatings in the containment are recoated on a periodic basis by personnel qualified consistent with LR
| |
| -ISG-2013-01 AMP XI.M42 and the periodicity is more frequent than that established in AMP XI.M42 Table 4a, "Inspection Intervals for Internal Coatings/Linings for Tanks, Piping, Piping Components, and Heat Exchangers." The staff's concern addressed in RAI 3.0.3.4
| |
| -1 is resolved.
| |
| The applicant augmented (enhanced) the programs: LRA Sections B.2.1.11, Open
| |
| -Cycle Cooling Water System; B.2.1.16, Fire Water System; B.2.1.18, Fuel Oil Chemistry; and B.2.1.25, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Programs, to include the requirements listed below.
| |
| | |
| Aging Management Review Results 3-253 Inspection Methods and Parameters Monitored. The applicant stated that it will conduct periodic visual inspections of all internal coatings for "indication[s] of blistering, cracking, flaking, peeling, or physical damage."
| |
| The staff noted that the applicant did not list spalling and rusting in its list of parameters to be inspected. However, the applicant revised the above
| |
| -referenced programs to include a chart titled "Inspection Intervals for Internal Service Level," because they are consistent with the recommendations associated with inspection methods and parameters monitored in AMP XI.M42, and periodic visual examinations are capable of detecting loss of coating integrity by inspecting for indications such as blistering, cracking, and flaking.
| |
| Inspection Timing, Frequency, and Extent. The applicant stated that baseline inspections will be conducted during the 10
| |
| -year period prior to the period of extended operation. The applicant also stated that subsequent inspections would be based on factors such as the effect of a coating failure, problems identified during prior inspections, and known service life history. The applicant further stated that the coatings specialist would determine the timing of subsequent inspections subject to not exceeding inspection intervals included in the Inspection Intervals for Internal Service Level 3 (augmented) Coatings for Tanks, Piping, and Heat Exchangers chart. The applicant stated that:
| |
| All accessible internal coated surfaces of tanks and heat exchangers will be inspected.
| |
| A representative sample of internally coated piping will be inspected. The representative sample for piping will consist of 73 1
| |
| -foot axial length circumferential segments of piping or 50 percent of the total length of each coating material and environment combination. The surface to be inspected will consist of the entire inside circumference of each 1
| |
| -foot segment and, if geometric limitations restricted access, the number of inspected segments will be increased to ensure that an equivalent of 73 1
| |
| -foot axial length circumferential segments will be inspected.
| |
| Coating inspections will not be conducted if there are no downstream effects of loss of coating integrity (e.g., reduction in flow, drop in pressure, or reduction in heat transfer) as long as the component's corrosion rates and inspection intervals were not based on the integrity of the coating. If loss of material is the only consideration for loss of coating integrity, external wall thickness measurements may be conducted in lieu of internal coating inspections.
| |
| The staff noted that Footnote 6 of the inspection interval chart is incomplete, in that it appears to be missing necessary text to form a complete statement. The staff understands that the intent of this footnote is to allow internal coating inspection intervals for diesel fuel oil storage tanks to meet the Inspection Intervals for Internal Service Level 3 (augmented) Coatings for Tanks, Piping, and Heat Exchangers chart requirements or to be consistent with GALL Report AMP XI.M30, if the prior inspection results in no peeling, delamination, blisters, or rusting being detected and any cracking and flaking having been found acceptable in accordance with the acceptance criteria.
| |
| The staff finds the timing of baseline inspections, frequency of subsequent inspections, and extent of inspections acceptable, because they are consistent with the associated Aging Management Review Results 3-254 recommendations to manage loss of coating integrity in AMP XI.M42, which can be sufficient to detect loss of coating integrity prior to a loss of intended function of an in-scope component.
| |
| Training and Qualifications. The applicant stated that, "[c]oatings specialists and inspectors will be qualified in accordance with ASTM International Standards." The staff lacks sufficient information to determine whether the coatings specialist and inspectors will be adequately qualified to conduct activities associated with coating integrity. The staff has currently only evaluated ASTM standards referenced in RG 1.54. By letter dated November 18, 2014, the staff issued RAI 3.0.3.4-2, requesting that the applicant state the specific ASTM standards that will be used to qualify coatings specialists and inspectors.
| |
| In its reply dated March 9, 2015, the applicant stated that coatings specialists and inspectors for coatings within the scope of LR
| |
| -ISG-2013-01 will be qualified in accordance with ASTM International Standards referenced in RG 1.54. The applicant amended LRA Sections B.2.1.11, B.2.1.16, B.2.1.18, and B.2.1.25 to include the new requirement for qualifications.
| |
| The staff finds the applicant's response acceptable because RG 1.54 references ASTM International Standards that contain NRC
| |
| -endorsed standards for qualifying individuals to conduct activities associated with coating inspections. The staff's concern described in RAI 3.0.3.4-2 is resolved.
| |
| Trending. The applicant stated that, before conducting coating inspections, the results of the previous two inspections and any repair activities will be reviewed. The applicant also stated that the coatings specialist's review will consist of "a list and location of all areas evidencing deterioration, a prioritization of the repair areas into areas that must be repaired before returning the system to service, areas where repair can be postponed to the next inspection, and, wher e possible, photographic evidence of inspection locations." The applicant further stated that, when wall thickness measurements are used, the rate of corrosion of the base metal will be trended. The staff noted that the information that will be contained in the inspection reports is consistent with the "monitoring and trending" program element of AMP XI.M42, which can ensure that the inspector will be informed of prior coating conditions. However, while it is clear that a coatings specialist will review the inspection results before the next inspection; it is not clear whether this individual will prepare the post
| |
| -inspection report. By letter dated November 18, 2014, the staff issued RAI 3.0.3.4
| |
| -3, requesting that the applicant state the qualification level of the individual who prepares the post
| |
| -inspection report.
| |
| In its reply dated March 9, 2015, the applicant stated that a coatings inspector or the coatings specialist will prepare the post
| |
| -inspection reports. The applicant also stated that, when an inspection report is prepared by a coatings inspector, the report will be reviewed by the coatings specialist.
| |
| The staff noted that the applicant amended LRA Sections B.2.1.11, B.2.1.16, B.2.1.18, and B.2.1.25 to include the new requirement for reviewing the previous two inspection reports before an inspection and preparing and reviewing post
| |
| -inspection reports. The staff finds the applicant's response acceptable because individuals with appropriate qualifications will prepare or review inspection reports and prior inspection reports will be reviewed to inform the inspector of the prior condition of the coatings. The staff's concern described in RAI 3.0.3.4
| |
| -3 is resolved.
| |
| | |
| Aging Management Review Results 3-255 Acceptance Criteria. The applicant stated that the acceptance criteria for coating inspections are as follows:
| |
| * Peeling and delamination are not acceptable and indications of this nature will be repaired or replaced.
| |
| * Physical testing, consisting of destructive or nondestructive adhesion testing at a minimum of three sample points adjacent to the degraded area will be conducted, where possible, when delamination or peeling is detected. The adhesion testing will be conducted in accordance with ASTM standards.
| |
| * Blisters will be evaluated by a coatings specialist and will be limited to blisters that are completely surrounded by sound coating material bounded to the surface. Inspections of the base material will be conducted in the vicinity of the blister to determine if unanticipated corrosion has occurred.
| |
| * Cracking, flaking, and rusting will be evaluated by a coating specialist.
| |
| * "[m]inor cracking and spalling of cementitious coatings is acceptable provided there is no evidence that the coating is debonding from the base material."
| |
| * Minimum wall thickness measurements meet design requirements.
| |
| * "[a]dhesion values provide reasonable assurance that the coating will remain bonded to the substrate as evaluated by the coating specialist."
| |
| The staff finds the applicant's acceptance criteria, with the exception of the following, acceptable because they are consistent with AMP XI.M42 and can ensure that degraded coatings that should be evaluated, repaired, replaced, or removed are identified. The criteria for accepting a blister for continued service do not state whether the coating specialist will consider the potential effects of flow blockage and degradation of the base material beneath the blister. Th e criterion for adhesion testing results does not state how reasonable assurance that coatings will remain bonded to the substrate will be determined. By letter dated November 18, 2014, the staff issued RAI 3.0.3.4
| |
| -4, requesting that the applicant state whether the potential effects of flow blockage and degradation of the base material beneath the blister will be considered in an accept-as-is disposition and how reasonable assurance that coatings will remain bonded to the substrate will be determined.
| |
| In its reply dated March 9, 2015, the applicant revised LRA Sections B.2.1.11, B.2.1.16, B.2.1.18, and B.2.1.25 to include: (a) the potential effects of flow blockage and degradation of the base material beneath a blister will be evaluated during an "accept
| |
| -as-is disposition" and (b) a coatings specialist will ensure that adhesion testing is conducted in accordance with ASTM D6677
| |
| -07, "Standard Test Method for Evaluating Adhesion by Knife," or ASTM 4541
| |
| -09, "Standard Test Method for Pull
| |
| -Off Strength of Coatings Using Portable Adhesion Testers."
| |
| The staff noted that the applicant stated that adhesion testing by knife would have a rating of 6 or better and adhesion testing by the pull
| |
| -off method would have an adhesion of 200 psi or better. The "acceptance criteria" program element of AMP XI.M42 states that adhesion test results are determined by plant
| |
| -specific procedures. The staff has no conclusion in regard to the stated plant
| |
| -specific values. The staff finds the applicant's response acceptable because:
| |
| (a) the applicant has revised its programs to include an evaluation of the localized and downstream effect of blisters by an appropriately qualified individual, (b) the staff has accepted Aging Management Review Results 3-256 (in RG 1.54) the use of ASTM D6677
| |
| -07 and ASTM 4541
| |
| -09 as effective methods for adhesion testing, and (c) the changes are consistent with AMP XI.M42. The staff's concern described in RAI 3.0.3.4
| |
| -4 is resolved.
| |
| Corrective Actions. In addition to the corrective actions stated in the above acceptance criteria, the applicant stated that indications will be entered into the corrective action program. The staff noted that the applicant did not state: (a) that coatings that do not meet acceptance criteria will be repaired or replaced, and (b) what testing will be conducted subsequent to the repair or replacement of coatings. By letter dated November 18, 2014, the staff issued RAI 3.0.3.4
| |
| -5, requesting that the applicant state whether coatings that do not meet acceptance criteria will be repaired or replaced and what testing will be conducted subsequent to the repair or replacement of coatings.
| |
| In its reply dated March 9, 2015, the applicant revised LRA Sections B.2.1.11, B.2.1.16, B.2.1.18, and B.2.1.25 to include the recommendations in the "corrective actions" program element of LR
| |
| -ISG-2013-01 associated with: (a) repair, replacement, or removal of coatings that do not meet acceptance criteria, (b) the alternative for returning coatings to service that exhibit indications of peeling and delamination, (c) examination of base metal in the vicinity of a blister when the coatings/linings are credited for corrosion prevention, and (d) physical testing associated with blisters that are not repaired.
| |
| The staff finds the applicant's response acceptable because the recommendations of the "corrective actions" program element of AMP XI.M42 were incorporated into the applicant's programs that manage loss of coating integrity for internal coatings/linings. These changes can ensure that either degraded coatings are repaired, replaced, or removed; or appropriate evaluations, testing, inspections, and actions to mitigate further degradation are conducted for coatings that do not meet the acceptance criteria. The staff's concern described in RAI 3.0.3.4-5 is resolved.
| |
| UFSAR Supplement. The applicant revised LRA Sections A.2.1.11, A.2.1.16, A.2.1.18, and A.2.1.25 to state that each respective program would manage loss of coating integrity. The staff noted that the applicant did not include any statements related to: (a) how coatings will be inspected, (b) the testing that will be conducted for coatings that are determined not to meet the acceptance criteria, and (c) the training and qualification of individuals involved in coating/lining inspections in the UFSAR supplement updates. By letter dated November 18, 2014, the staff issued RAI 3.0.3.4
| |
| -6, requesting that the applicant state the basis for how the UFSAR supplements provide an adequate summary description of the activities to manage the aging of internal coatings of piping, piping components, heat exchangers, and tanks.
| |
| In its reply dated March 9, 2015, the applicant revised LRA Sections A.2.1.11, A.2.1.16, A.2.1.18, and A.2.1.25 to state that: (a) periodic visual inspections will be conducted, (b) physical testing will be performed, where possible, for coated/lined surfaces that do not meet acceptance criteria, and (c) personnel involved in inspection activities will be qualified by standards endorsed in RG 1.54 or an appropriate combination of education and experience for inspection of cementitious coatings.
| |
| The staff finds the applicant's response acceptable because the revised LRA sections are consistent with Table 3.0
| |
| -1, AMP XI.M42, as modified by LR
| |
| -ISG-2013-01. The staff's concern described in RAI 3.0.3.4
| |
| -6 is resolved.
| |
| | |
| Aging Management Review Results 3-257 The staff also noted that the applicant committed, in Commitment Nos. 79, 80, 81, and 82, to enhancing the respective programs to include visual inspection of coatings within 10 years prior to the period of extended operation.
| |
| Conclusion. On the basis of its review of the proposed changes to the Open
| |
| -Cycle Cooling Water System, Fire Water System, Fuel Oil Chemistry, and Internal Surfaces in Miscellaneous Piping and Ducting Components Programs, as amended by letters dated March 5, 2014, March 9, 2015, and May 19, 2015, the staff determines that those program elements for which the applicant claimed consistency with LR
| |
| -IS G-2013-01, AMP XI.M42, are consistent. In addition, the staff reviewed the enhancements and confirmed that their implementation through Commitment Nos. 79 (within 10 years prior to the period of extended operation), 80 (within 10 years prior to the period of extended operation), 81 (within 10 years prior to the period of extended operation), 82 (within 10 years prior to the period of extended operation), and 89 (prior to the period of extended operation) will make the AMPs adequate to manage the applicable aging effects. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplements for these AMPs and concludes that they provide an adequate summary description of the program, as required by 10 CFR 54.21(d).
| |
| | |
| ====3.0.4 Quality====
| |
| Assurance Program Attributes Integral to Aging Management Programs 3.0.4.1 Summary of Technical Information in the Application In Appendix A, "Updated Final Safety Analysis Report Supplement," Section A.1.5, "Quality Assurance Program and Administrative Controls," and Appendix B, "Aging Management Programs," Section B.1.3, "Quality Assurance Program and Administrative Controls," of the LRA, the applicant described the elements of corrective action, confirmation process, and administrative controls that are applied to the AMPs for both safety
| |
| -related and nonsafety
| |
| -related components. The FPL/NextEra Energy Quality Assurance Program (QAP) is used, which includes the elements of corrective action, confirmation process, and administrative controls. Corrective actions, confirmation process, and administrative controls are applied in accordance with the QAP regardless of the safety classification of the components. Appendix A, Section A.1.5 and Appendix B, Section B.1.3, of the LRA state that the QAP implements the requirements of 10 CFR Part 50, Appendix B, "Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants," and is consistent with the NUREG
| |
| -1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants (SRP
| |
| -LR)," Revision 1.
| |
| 3.0.4.2 Staff Evaluation Pursuant to 10 CFR 54.21(a)(3), an applicant is required to demonstrate that the effects of aging on SCs subject to an AMR will be adequately managed so that their intended functions will be maintained consistent with the CLB for the period of extended operation. The SRP
| |
| -LR, Branch Technical Position RLSB
| |
| -1, "Aging Management Review
| |
| -Generic," describes 10 attributes of an acceptable AMP. Of these 10 attributes, 3 are associated with the QA activities of corrective action, confirmation process, and administrative controls. Table A.1
| |
| -1, "Elements of an Aging Management Program for License Renewal," of Branch Technical Position RLSB
| |
| -1 provides the following description of these quality attributes:
| |
| | |
| Aging Management Review Results 3-258
| |
| * Attribute No. 7
| |
| -Corrective Actions, including root cause determination and prevention of recurrence, should be timely.
| |
| * Attribute No. 8
| |
| -Confirmation Process, which should ensure that preventive actions are adequate and that appropriate corrective actions have been completed and are effective.
| |
| * Attribute No. 9
| |
| -Administrative Controls, which should provide a formal review and approval process.
| |
| The SRP-LR, Branch Technical Position IQMB
| |
| -1, "Quality Assurance for Aging Management Programs," states that those aspects of the AMP that affect quality of safety
| |
| -related SSCs are subject to the QA requirements of 10 CFR Part 50, Appendix B. Additionally, for nonsafety-related SCs subject to an AMR, the applicant's existing 10 CFR Part 50, Appendix B, QAP may be used to address the elements of corrective action, confirmation process, and administrative control. Branch Technical Position IQMB
| |
| -1 provides the following guidance with regard to the QA attributes of AMPs:
| |
| Safety-related SCs are subject to Appendix B to 10 CFR Part 50 requirements which are adequate to address all quality related aspects of an AMP consistent with the CLB of the facility for the period of extended operation. For nonsafety
| |
| -related SCs that are subject to an AMR for license renewal, an applicant has an option to expand the scope of its Appendix B to 10 CFR Part 50 program to include these SCs to address corrective action, confirmation process, and administrative control for aging management during the period of extended operation. In this case, the applicant should document such a commitment in the Final Safety Analysis Report supplement in accordance with 10 CFR 54.21(d).
| |
| The staff reviewed the applicant's AMPs described in Appendix A and Appendix B of the LRA, AMP basis documents, and the associated implementing procedures. The purpose of this review was to confirm that the QA attributes (corrective action, confirmation process, and administrative controls) were consistent with the staff's guidance described in Branch Technical Position IQMB
| |
| -1. Based on the staff's evaluation, the descriptions of the AMPs and their associated quality attributes provided in Appendix A, Section A.1.5, and Appendix B, Section B1.3, of the LRA are consistent with the staff's position regarding QA for aging management.
| |
| 3.0.4.3 Conclusion On the basis of the staff's evaluation, the descriptions and applicability of the plant
| |
| -specific AMPs and their associated quality attributes provided in Appendix A, Section A.1.5, and Appendix B, Section B1.3 of the LRA, were determined to be consistent with the staff's position regarding QA for aging management. The staff concludes that the QA attributes (corrective action, confirmation process, and administrative control) of the applicant's AMPs are consistent with 10 CFR 54.21(a)(3).
| |
| | |
| Aging Management Review Results 3-259 3.0.5 Operating Experience 3.0.5.1 Summary of Technical Information in the Application LRA Section B.1.4 describes the consideration of operating experience for AMPs. The LRA states that operating experience for existing programs and activities was reviewed as an input to the AMP evaluations. This review included plant records, such as reports generated under the corrective action program, and was focused on degradation due to aging
| |
| -related issues. The LRA also states that the operating experience review considered the results of plant
| |
| -specific and industry operating experience and interviews with site personnel. Further, LRA Section 3.0.3 states that, "ongoing review of plant
| |
| -specific and industry operating experience is performed in accordance with the plant Operating Experience Program and as a part of selected Seabrook Station aging management programs."
| |
| 3.0.5.2 Staff Evaluation The staff issued its final License Renewal Interim Staff Guidance LR
| |
| -ISG-2011-05, "Ongoing Review of Operating Experience," dated March 16, 2012, which clarifies that AMPs should be informed, and enhanced when necessary, based on the ongoing review of both plant
| |
| -specific and industry operating experience. Also, pursuant to 10 CFR 54.21(a)(3), an applicant is required to demonstrate that the effects of aging on systems, structures, and components subject to an AMR will be adequately managed so that its intended functions will be maintained consistent with the CLB for the period of extended operation. SRP
| |
| -LR, Revision 2, Appendix A, describes 10 elements of an acceptable AMP. Section A.1.2.3.10 describes element 10, "operating experience," as consisting of these three attributes:
| |
| (1) Consideration of future plant
| |
| -specific and industry operating experience relating to aging management programs should be discussed. Reviews of operating experience by the applicant in the future may identify areas where aging management programs should be enhanced or new programs developed. An applicant should commit to a future review of plant-specific and industry operating experience to confirm the effectiveness of its aging management programs or indicate a need to develop new aging management programs. This information should provide objective evidence to support the conclusion that the effects of aging will be managed adequately so that the structure and component intended function(s) will be maintained during the period of extended operation.
| |
| (2) Operating experience with existing programs should be discussed. The operating experience of AMPs that are existing programs, including past corrective actions resulting in program enhancements or additional programs, should be considered. A past failure would not necessarily invalidate an AMP because the feedback from operating experience should have resulted in appropriate program enhancements or new programs. This information can show where an existing program has succeeded and where it has failed (if at all) in intercepting aging degradation in a timely manner. This information should provide objective evidence to support the conclusion that the effects of aging will be managed adequately so that the structure
| |
| - and component
| |
| - intended function(s) will be maintained during the period of extended operation.
| |
| (3) For new AMPs that have yet to be implemented at an applicant's facility, the programs have not yet generated any operating experience. However, there may be other Aging Management Review Results 3-260 relevant plant
| |
| -specific operating experience at the plant or generic operating experience in the industry that is relevant to the AMP's program elements even though the operating experience was not identified as a result of the implementation of the new program. Thus, for new programs, an applicant may need to consider the impact of relevant operating experience that results from the past implementation of its existing AMPs that are existing programs and the impact of relevant generic operating experience on developing the program elements. Therefore, operating experience applicable to new programs should be discussed. Additionally, an applicant should commit to a review of future plant
| |
| -specific and industry operating experience for new programs to confirm its effectiveness.
| |
| SER Section 3.0.3 discusses the staff's review of the second and third attributes, which concern operating experience associated with existing and new programs, respectively. The evaluation below discusses the staff's review of the first attribute, which concerns the consideration of future operating experience and is applicable to both new and existing programs.
| |
| The staff reviewed LRA Sections B.1.4 and B.2.1.1 through B.2.3.2 to determine whether the applicant will implement adequate activities for the continual review of both plant
| |
| -specific and industry operating experience to identify areas where AMPs should be enhanced or new AMPs developed. The staff determined that these LRA sections describe how the applicant incorporated operating experience into its AMPs, but they do not fully describe how the applicant will use future operating experience to ensure that the AMPs will remain effective for managing the aging effects during the period of extended operation. While the program descriptions contain statements indicating that future operating experience will be used to adjust the programs as appropriate, the details of this process are not fully described.
| |
| It was not clear to the staff whether the applicant intends to implement actions to monitor operating experience on an ongoing basis and use it to ensure the continued effectiveness of these AMPs. Further, the LRA does not state whether new AMPs will be developed, as necessary.
| |
| By letters dated May 23, 2011, and December 12, 2011, the staff issued RAI B.1.4
| |
| -1 and RAI B.1.4-2, requesting that the applicant describe in detail the programmatic activities that will be used to continually identify aging issues, evaluate them, and, as necessary, enhance the AMPs or develop new AMPs.
| |
| By letters dated June 24, 2011, and January 20, 2012, the applicant provided its response to the staff's RAIs. Subsequent to receipt of the applicant's response, the staff also issued its final License Renewal Interim Staff Guidance LR
| |
| -ISG-2011-05, "Ongoing Review of Operating Experience." The issue of the adequacy of the applicant's Operating Experience Program, pursuant to LR
| |
| -ISG-2011-05, was identified as Open Item OI B.1.4-2. The staff has completed its evaluation of the applicant's response to RAI B.1.4
| |
| -1 and RAI B.1.4-2 against the LR
| |
| -ISG-2011-05 guidance. The staff evaluation is discussed below.
| |
| Acceptability of Existing Programs. SRP-LR Section A.4.2 describes existing programs generally acceptable to the staff for the capture, processing, and evaluation of operating experience concerning age
| |
| -related degradation and aging management during the term of a renewed operating license. The acceptable programs are those relied upon to meet the requirements of 10 CFR Part 50 and NUREG
| |
| -0737, "Clarification of TMI Action Plan Aging Management Review Results 3-261 Requirements," item I.C.5. SRP
| |
| -LR Section A.4.2 also states that, as part of meeting the requirements of NUREG
| |
| -0737, item I.C.5, the applicant's Operating Experience Program should rely on active participation in the INPO operating experience program (formerly the INPO Significant Event Evaluation and Information Network (SEE
| |
| -IN) program endorsed in NRC GL 82-04, "Use of INPO SEE
| |
| -IN Program," dated March 9, 1982).
| |
| In response to RAI B.1.4
| |
| -1, the applicant stated that it will use its Operating Experience Program and corrective action program to review industry and plant
| |
| -specific operating experience to confirm the effectiveness of the license renewal AMPs and determine when AMP enhancements or new AMPs are needed. The applicant stated that the corrective action program is governed by its Quality Assurance Program, which meets the requirements of 10 CFR Part 50, Appendix B, and that the Operating Experience Program meets the criteria of NUREG-0737, item I.C.5. The applicant also stated that the Operating Experience Program includes the review of INPO documents for operating experience and, in response to RAI B.1.4
| |
| -2, the applicant stated that it will report its own plant
| |
| -specific operating experience concerning age-related degradation to industry using the INPO Nuclear Network. Based on this information, the staff determined that the applicant's corrective action program and Operating Experience Program are consistent with the programs described in SRP
| |
| -LR Section A.4.2 and, therefore, generally acceptable for the capture, processing, and evaluation of age
| |
| -related operating experience.
| |
| Notwithstanding the general acceptability of existing programs, certain areas of the applicant's operating experience review activities (for future program consideration) are subject to further staff review as described in SRP
| |
| -LR Section A.4.2. These areas include, but are not limited to: (a) application of existing programs and procedures to the processing of operating experience related to aging, (b) consideration of guidance documents as industry operating experience, (c) screening of incoming operating experience, (d) identification of operating experience related to aging, (e) information considered in operating experience evaluations, (f) evaluation of AMP implementation results, (g) training, (h) reporting operating experience to the industry, and (i) schedule for implementing the operating experience review activities.
| |
| Application of Existing Programs and Procedures to the Processing of Operating Experience Related to Aging. SRP-LR Section A.4.2 states that the programs and procedures relied upon to meet the requirements of 10 CFR Part 50, Appendix B, and NUREG
| |
| -0737, item I.C.5, should not preclude the consideration of operating experience on age
| |
| -related degradation and aging management. In response to RAI B.1.4
| |
| -1, the applicant stated that it requires aging issues that constitute a potential condition adverse to quality to be entered into the corrective action program. The applicant explained that these issues include degraded conditions that could reduce SSC capability as a result of aging, erosion, corrosion, etc. Also, in response to RAI B.1.4
| |
| -2, the applicant stated that it will require AMP owners to review relevant operating experience and revise their respective AMPs based on plant
| |
| -specific and industry operating experience, technology changes, and revisions to applicable codes and standards. As an enhancement, the applicant stated that it will revise its procedures to direct entry of operating experience affecting AMPs into the Operating Experience Program. The staff reviewed these responses and determined that the applicant's programs will not preclude the capture and evaluation of operating experience related to aging because: (a) the applicant demonstrated that the corrective action program currently applies to age
| |
| -related operating experience, and (b) the applicant will enhance the Operating Experience Program so that it will specifically apply to age
| |
| -related operating experience. The applicant's use of these programs Aging Management Review Results 3-262 for processing operating experience is, therefore, consistent with the guidance in SRP
| |
| -LR Section A.4.2.
| |
| SRP-LR Section A.4.2 also states that the applicant should use the option described in SRP
| |
| -LR Appendix A.2 to expand the scope of the 10 CFR Part 50, Appendix B, program to include nonsafety-related SCs. As discussed in SER Section 3.0.4, the staff determined that the applicant's inclusion of nonsafety
| |
| -related SCs within the scope of its 10 CFR Part 50, Appendix B, program is consistent with the guidance in SRP
| |
| -LR Appendix A.2 and, therefore, also consistent with the guidance in SRP
| |
| -LR Section A.4.2.
| |
| Consideration of Guidance Documents as Industry Operating Experience. SRP-LR Section A.4.2 states that NRC and industry guidance documents and standards applicable to aging management, including revisions to the GALL Report, should be considered as sources of industry operating experience and evaluated accordingly.
| |
| In response to RAI B.1.4
| |
| -2, the applicant stated that it evaluates guidance documents as sources of industry operating experience. The applicant stated that, under its Operating Experience Program, it specifically reviews NRC generic communications; INPO, industry, and owner's group communications; Nuclear Energy Institute, Electric Power Research Institute, and vendor reports; and operating experience from its own fleet of plants. In addition, the applicant stated that it will review future GALL Report revisions, other applicable NUREGs, and LR-ISG documents. The applicant indicated that its operating experience reviews are not limited to these specific sources and, as an enhancement, the applicant stated that it will revise its procedures to direct entry of operating experience affecting AMPs into the Operating Experience Program. The applicant further stated that it will require AMP owners to review relevant industry operating experience, technology changes, and revisions to applicable codes and standards, and revise their respective AMPs accordingly.
| |
| The staff reviewed the sources of industry operating experience that the applicant will review under its Operating Experience Program. The staff determined that the sources prescribed for review are acceptable because the staff considers them to be the primary sources of industry operating experience information. These sources are also consistent with the sources outlined in the INPO guidelines, which the staff has endorsed by GL 82
| |
| -04. The staff also determined that the applicant's review of future GALL Report revisions and LR
| |
| -ISG documents is appropriate. Through its updates of the GALL Report and issuance of LR
| |
| -ISGs, the staff has emphasized that these documents contain new information and important lessons learned that are relevant to maintaining the effectiveness of AMPs. In addition, the staff determined that the enhancement to include operating experience affecting AMPs in the Operating Experience Program, along with the AMP owner activities to identify applicable industry guidance and standards, will ensure that the applicant considers other appropriate sources. Based on its review, the staff finds that the applicant will consider an appropriate breadth of industry operating experience for impacts to the AMPs. The applicant's consideration of industry guidance documents as operating experience is, therefore, consistent with the guidance in SRP-LR Section A.4.2.
| |
| Screening of Incoming Operating Experience. SRP-LR Section A.4.2 states that all incoming plant-specific and industry operating experience should be screened to determine if it involves age-related degradation or impacts to aging management activities. In response to RAI B.1.4
| |
| -2, the applicant described how it will screen for and evaluate age
| |
| -related operating experience. The applicant stated that personnel responsible for screening plant
| |
| -specific and industry Aging Management Review Results 3-263 operating experience will receive training so that they can effectively identify and assess age
| |
| -related issues. The applicant stated that the operating experience evaluations will determine the need to modify, enhance, or develop new AMPs, based on the consideration of attributes fundamental to an AMR, and the personnel training will also cover how these attributes should be considered in the operating experience evaluations. The staff reviewed this information and determined that the applicant's operating experience review processes are acceptable because they include screening of operating experience by trained individuals so that items with potential impact to aging management can receive appropriate evaluation. The applicant's screening of plant-specific and industry operating experience is, therefore, consistent with the guidance in SRP-LR Section A.4.2.
| |
| Identification of Operating Experience Related to Aging. SRP-LR Section A.4.2 states that coding should be used within the plant's corrective action program to identify operating experience involving age
| |
| -related degradation applicable to the plant, and the associated entries should be periodically reviewed with further evaluation of any adverse trends. In response to RAI B.1.4-2, the applicant stated that, as an enhancement, it will develop a new trend code to track and facilitate trending of age
| |
| -related degradation issues and operating experience in its corrective action program. The applicant also stated that it will apply existing performance monitoring and trending activities to age
| |
| -related operating experience and evaluate trend results for impacts to the AMPs. The staff reviewed the applicant's response to RAI B.1.4
| |
| -2 and could not determine whether the performance monitoring and trending activities would include periodic review of items associated with the new age
| |
| -related trend code. By letter dated September 10, 2012, the staff issued RAI B.1.4
| |
| -4, requesting that the applicant indicate whether it will periodically review items associated with the trend code to determine if there are any adverse trends. The applicant responded to RAI B.1.4
| |
| -4 by letter dated September 18, 2012. The applicant explained that it periodically analyzes and trends data in the corrective action program and evaluates any adverse trends. The applicant confirmed that it will also apply these practices to the new age
| |
| -related trend code. The staff reviewed the activities described in response to RAIs B.1.4
| |
| -1 and B.1.4
| |
| -4 and finds them acceptable because the applicant will establish a means at a programmatic level to identify, trend, and evaluate operating experience that involves age
| |
| -related degradation. The applicant's identification of age
| |
| -related operating experience applicable to the plant is, therefore, consistent with the guidance in SRP
| |
| -LR Section A.4.2. Information Considered in Operating Experience Evaluations. SRP-LR Section A.4.2 states that operating experience identified as involving aging should receive further evaluation based on consideration of the affected SSCs, materials, environments, aging effects, aging mechanisms, and AMPs. In response to RAI B.1.4
| |
| -2, the applicant stated that SSCs, materials, environments, aging effects, aging mechanisms, and AMPs are fundamental attributes considered in the evaluation of operating experience involving aging issues. The applicant also stated that assessments based on these attributes will be used to determine the need to modify, enhance, or develop new AMPs. Based on review of this information, the staff determined that the applicant's evaluations of age
| |
| -related operating experience will include assessment of potential impacts to aging management activities using appropriate aging management considerations.
| |
| SRP-LR Section A.4.2 also states that actions should be initiated within the corrective action program to either enhance the AMPs or develop and implement new AMPs if it is found, through an operating experience evaluation, that the effects of aging may not be adequately managed.
| |
| Aging Management Review Results 3-264 In its response to RAI B.1.4
| |
| -1, the applicant stated that it will review plant
| |
| -specific and industry operating experience to confirm the effectiveness of the AMPs and determine the need for AMP enhancements or new AMPs. The applicant also stated that it will track and implement necessary changes to the existing AMPs through the corrective action program. In response to RAI B.1.4-2, the applicant stated that it will also implement new AMPs through the corrective action program. The staff reviewed these responses and determined that the applicant will use its corrective action program to implement changes necessary to manage the effects of aging, as determined through the evaluation of operating experience.
| |
| The staff finds that the information considered in the applicant's operating experience evaluations and use of the corrective action program to ensure that the effects of aging are adequately managed is consistent with the guidance in SRP
| |
| -LR Section A.4.2.
| |
| Evaluation of AMP Implementation Results. SRP-LR Section A.4.2 states that the results of implementing the AMPs, such as data from inspections, tests, and analyses, should be evaluated regardless of whether the acceptance criteria of the particular AMP have been met. SRP-LR Section A.4.2 states that this information should be used to determine if it is necessary to adjust the inspection activities for aging management. In addition, SRP
| |
| -LR Section A.4.2 states that actions should be initiated within the plant's corrective action program to either enhance the AMPs or develop and implement new AMPs, if these evaluations indicate that the effects of aging may not be adequately managed. In response to RAI B.1.4
| |
| -2, the applicant stated that it enters the results from AMP inspection, test, analysis, and similar activities into its asset management system. The applicant stated that it records these results both when they meet and do not meet the applicable acceptance criteria, which allows the applicant to consider this information as operating experience. The applicant also stated that it will require the AMP owners to review relevant plant
| |
| -specific and industry operating experience and revise their respective AMPs accordingly. The need for enhanced or new AMPs, or other specific actions , will be evaluated and implementation under the applicant's corrective action program. The staff reviewed this response and finds the applicant's treatment of AMP implementation results as operating experience acceptable because the applicant will evaluate these results and use the information to determine whether to adjust the aging management activities. The applicant's activities for the evaluation of the AMP implementation results are, therefore, consistent with the guidance in SRP
| |
| -LR Section A.4.2.
| |
| Training. SRP-LR Section A.4.2 states that training on age
| |
| -related degradation and aging management should be provided to those personnel responsible for implementing the AMPs and those who may submit, screen, assign, evaluate, or otherwise process plant
| |
| -specific and industry operating experience. SRP
| |
| -LR Section A.4.2 also states that the training should be periodic and include provisions to accommodate the turnover of plant personnel. In its response to RAI B.1.4
| |
| -2, the applicant stated that, as an enhancement, it will complete a training assessment and needs analysis to establish training requirements for plant personnel with respect to knowledge and consideration of age
| |
| -related operating experience. The applicant stated that it will use a systematic approach to training and qualification development per its existing training program. The applicant's training assessment will establish the type and periodicity of training and the activities necessary to account for personnel turnover. The staff reviewed the response and finds it acceptable because the applicant will establish and require initial and periodic training on age
| |
| -related degradation and aging management topics for key personnel responsible for processing and evaluating operating experience related to aging. The staff also finds the response acceptable because the applicant will establish an approach to Aging Management Review Results 3-265 address training for the turnover of personnel. The applicant's enhanced training activities are, therefore, consistent with the guidance in SRP-LR Section A.4.2.
| |
| Reporting Operating Experience to the Industry. SRP-LR Section A.4.2 states that guidelines should be established for reporting plant
| |
| -specific operating experience on age
| |
| -related degradation and aging management to the industry. In response to RAI B.1.4
| |
| -2, the applicant stated that it will report its operating experience involving age
| |
| -related issues using the same criteria as for issues that are not related to material aging. The applicant also described its current reporting criteria. The staff reviewed these criteria and determined that they are general and do not specifically address circumstances under which the applicant will identify and report age-related operating experience. In RAI B.1.4
| |
| -4, the staff requested that the applicant describe guidelines that specifically address reporting of operating experience concerning age
| |
| -related degradation and aging management.
| |
| The applicant responded to RAI B.1.4
| |
| -4 by letter dated September 18, 2012. The applicant stated that it revised its procedures to require the participation of a license renewal subject matter expert on the operating experience screening team to ensure the appropriate reporting of operating experience related to aging. In a supplement to this response dated December 10, 2012, the applicant described the qualifications and responsibilities of this individual. One such responsibility is to review plant
| |
| -specific operating experience to identify age-related failures, significant degradation of SSCs within the scope of license renewal, and instances where AMPs did not prevent failures and degradation. The staff reviewed this information and determined that the applicant has established appropriate expectations and guidelines for identifying and communicating noteworthy plant-specific operating experience concerning aging management and age
| |
| -related degradation to the industry. The applicant's establishment of these guidelines is, therefore, consistent with the guidance in SRP
| |
| -LR Section A.4.2. Schedule for Implementing the Operating Experience Review Activities. SRP-LR Section A.4.2 states that any enhancements to the existing operating experience review activities should be put in place no later than the date when the renewed operating license is issued. In response to RAI B.1.4-2, the applicant identified several enhancements to its existing operating experience review activities and stated that it will complete these enhancements as part of implementation of the renewed license. From this information, however, it was not clear to the staff whether the applicant would complete implementation by issuance of the renewed operating license. In RAI B.1.4-4, the staff requested the applicant to clarify when the enhancements will be implemented. In its response, the applicant explained that it will implement the enhancements by issuance of the renewed operating license. The staff reviewed the applicant's response and finds the schedule for implementing the programmatic enhancements acceptable because the applicant will complete implementation before issuance of the renewed license, which is consistent with the guidance in SRP
| |
| -LR Section A.4.2.
| |
| SRP-LR Section A.4.2 also states that the operating experience review activities should be implemented on an ongoing basis throughout the term of the renewed license. By letter dated August 25, 2011, as amended by letter dated July 2, 2013, the applicant included a summary description of its programmatic activities for the ongoing review of operating experience in the UFSAR supplement. This summary description states that the enhanced operating experience review activities will be implemented on an ongoing basis throughout the term of the renewed license. As discussed below in SER Section 3.0.5.3, the staff finds that this summary Aging Management Review Results 3-266 description is sufficiently comprehensive to describe the applicant's programmatic activities for evaluating operating experience. Upon issuance of the renewed license, in accordance with 10 CFR 54.3(c), this summary description will be incorporated into the plant's CLB and, at that time, the applicant will be obligated to conduct its operating experience review activities accordingly. The staff finds the implementation schedule acceptable because the applicant will implement the enhanced operating experience review activities on an ongoing basis throughout the term of the renewed operating license. This ongoing implementation is, therefore, consistent with the guidance in SRP
| |
| -LR Section A.4.2.
| |
| Summary. Based on a review of the applicant's responses to RAIs B.1.4
| |
| -1, B.1.4-2, and B.1.4
| |
| -4, as supplemented, the staff determined that the applicant's programmatic activities for the ongoing review of operating experience are consistent with the guidance in SRP
| |
| -LR Section A.4.2, as established in LR
| |
| -ISG-2011-05. These activities are, therefore, acceptable for (a) the systematic review of plant
| |
| -specific and industry operating experience to ensure that the license renewal AMPs are and will continue to be effective in managing the aging effects for which they are credited, and (b) the enhancement of AMPs or development of new AMPs when it is determined, through the evaluation of operating experience, that the effects of aging may not be adequately managed. Based on completion of the staff's review and the consistency of the applicant's operating experience review activities with the guidance in LR
| |
| -ISG-2011-05, the staff's concerns described in RAIs B.1.4
| |
| -1, B.1.4-2, and B.1.4
| |
| -4 are resolved and Open Item OI B.1.4-2 is closed.
| |
| 3.0.5.3 UFSAR Supplement The staff reviewed the UFSAR supplement in LRA Appendix A to determine whether the applicant provided an adequate summary description of the programmatic activities for the ongoing review of operating experience. As the staff found no such description, it also requested in RAI B.1.4
| |
| -1 that the applicant provide a description of these activities for the UFSAR supplement required by 10 CFR 54.21(d).
| |
| In its response dated August 25, 2011, the applicant provided the following summary description of the operating experience review activities for the UFSAR supplement:
| |
| The existing Corrective Action Program and the Operating Experience Program ensure, through the continual review of both plant
| |
| -specific and industry operating experience, that the license renewal aging management programs are effective to manage the aging effects for which they are credited. The programs are either enhanced or new programs are developed when the review of operating experience indicates that the programs may not be effective. For each aging management program, operating experience is reviewed on a continuing basis.
| |
| The staff reviewed this UFSAR supplement description against the acceptance criteria in SRP
| |
| -LR Sections 3.1.2.5, 3.2.2.5, 3.3.2.5, 3.4.2.5, 3.5.2.5, and 3.6.2.5. In accordance with these sections, the summary description should be sufficiently comprehensive such that later changes can be controlled by 10 CFR 50.59. With respect to these criteria, the staff determined that this summary description is not sufficiently comprehensive.
| |
| The applicant described generally how it intends to consider operating experience on an ongoing basis; however, it did not provide specific information on how its operating experience review activities address issues related to aging. Similarly, the above entry for UFSAR Aging Management Review Results 3-267 supplement also lacks detail on how aging is considered in the ongoing operating experience reviews. By letter dated December 12, 2011, the staff requested the applicant to clarify the UFSAR summary description provided in the applicant's letter dated August 25, 2011.
| |
| The staff also issued its final License Renewal Interim Staff Guidance LR
| |
| -ISG-2011-05, "Ongoing Review of Operating Experience." The issue of the applicant operating experience program adequacy was identified as Open Item OI B.1.4
| |
| -2. By letter dated January 20, 2012, the applicant responded to RAI B.1.4
| |
| -3 by revising LRA Section A.1.6. The revision includes a description of the enhancements for personnel training on identification and evaluation of age
| |
| -related issues, identification and tracking of age
| |
| -related operating experience in the corrective action program, and incorporation of guidance documents applicable to aging management into the operating experience review process. The revised summary description specifically states that the operating experience reviews will include LR
| |
| -ISG documents and future revisions of the GALL Report. In addition, the revised summary description states that the evaluations of age
| |
| -related operating experience will consider information such as the potentially affected SSCs, materials, environments, aging effects, aging mechanisms, and AMPs. By letter dated September 18, 2012, the applicant revised LRA Section A.1.6 to include additional information. Specifically, this revision states that the training activities will be periodic and account for personnel turnover. It also states that the applicant will report its own noteworthy operating experience related to aging to the industry. The applicant added a statement to explain that the enhanced operating experience review activities will be implemented no later than upon issuance of the renewed operating license and implemented on an ongoing basis thereafter. Also, in a supplement to the LRA dated July 2, 2013, the applicant included additional information on the bases for the corrective action program and Operating Experience Program. Specifically, the applicant revis ed LRA Section A.1.6 to indicate that the corrective action program is part of the Quality Assurance Program, which meets the requirements of 10 CFR Part 50, Appendix B, and that the Operating Experience Program meets the criteria of NUREG
| |
| -0737, item I.C.5, and interfaces with the INPO operating experience program.
| |
| SRP-LR Section A.4.2, as established in LR
| |
| -ISG-2011-05, states that the programmatic activities for the ongoing review of plant
| |
| -specific and industry operating experience concerning age-related degradation and aging management should be described in the UFSAR supplement. LR
| |
| -ISG-2011-05 also revises SRP
| |
| -LR Table 3.0
| |
| -1 to include an example of a summary description. The staff reviewed the content of LRA Section A.1.6, as amended by letter dated July 2, 2013, against the content in the example from SRP
| |
| -LR Table 3.0
| |
| -1. Based on its review, the staff determined that the content of the applicant's summary description is consistent with this example and also sufficiently comprehensive to describe the programmatic activities for evaluating operating experience to maintain the effectiveness of the AMPs. Therefore, the staff finds the applicant's UFSAR supplement summary description acceptable. The staff's concerns in RAIs B.1.4
| |
| -1 and B.1.4
| |
| -3 regarding the UFSAR supplement are resolved.
| |
| 3.0.5.4 Conclusion Based on its review of the applicant's programmatic activities for the ongoing review of operating experience, as described in responses to RAIs B.1.4
| |
| -1, B.1.4-2, B.1.4-3, and B.1.4
| |
| -4, as supplemented and amended, the staff concludes that the applicant has demonstrated that operating experience will be reviewed to ensure that the effects of aging will be adequately Aging Management Review Results 3-268 managed so that the intended functions will remain consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for these activities and concludes that it provides an adequate summary description, as required by 10 CFR 54.21(d).
| |
| | |
| ===3.1 Aging===
| |
| Management of Reactor Coolant System This section of the SER documents the staff's review of the applicant's AMR results for the RCS components and component groups of the following:
| |
| * RCS
| |
| * reactor vessel
| |
| * RVIs
| |
| * steam generator
| |
| | |
| ====3.1.1 Summary====
| |
| of Technical Information in the Application LRA Section 3.1 provides AMR results for the RCS, reactor vessel, RVIs, and steam generator.
| |
| LRA Table 3.1.1, "Summary of Aging Management Evaluations for the Reactor Vessel, Internals, and Reactor Coolant System," is a summary comparison of the applicant's AMRs with those evaluated in the GALL Report for the RCS, reactor vessel, RVIs, and steam generator components and component groups.
| |
| The applicant's AMRs evaluated and incorporated applicable plant
| |
| -specific and industry operating experience in the determination of AERMs. The plant
| |
| -specific evaluation included issue reports and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a review of the GALL Report and operating experience issues identified since the issuance of the GALL Report.
| |
| | |
| ====3.1.2 Staff====
| |
| Evaluation The staff reviewed LRA Section 3.1 to determine if the applicant provided sufficient information to demonstrate that the effects of aging for the RCS, reactor vessel, RVIs, and steam generator components within the scope of license renewal and subject to an AMR will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| The staff reviewed the AMRs to confirm the applicant's claim that certain identified AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant had identified the appropriate GALL Report AMRs. Details of the staff's evaluation are discussed in SER Section 3.1.2.1.
| |
| The staff reviewed AMRs consistent with the GALL Report and for which further evaluation is recommended. The staff confirmed that the applicant's further evaluations were consistent with the SRP-LR Section 3.1.2.2 acceptance criteria. The staff's evaluations are documented in SER Section 3.1.2.2.
| |
| The staff also reviewed the AMRs not consistent with or not addressed in the GALL Report. The technical review evaluated whether all plausible aging effects were identified and whether Aging Management Review Results 3-269 the aging effects listed were appropriate for the specified material
| |
| -environment combinations. Details of the staff's evaluation are presented in SER Section 3.1.2.3.
| |
| For components that the applicant claimed were not applicable or required no aging management, the staff reviewed the AMR items and the plant's operating experience to verify the applicant's claims.
| |
| Table 3.1-1 summarizes the staff's evaluation of components, aging effects or mechanisms, and AMPs listed in LRA Section 3.1 and addressed in the GALL Report.
| |
| Table 3.1-1. Staff Evaluation for Reactor Vessel, Reactor Vessel Internals, and Reactor Coolant System Components in the GALL Report Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Steel pressure vessel support skirt and attachment welds (3.1.1-1) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c)
| |
| Yes Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| Steel; stainless steel; steel with Ni
| |
| -alloy or stainless steel cladding; Ni
| |
| -alloy RV components: flanges; nozzles; penetrations; safe ends; thermal sleeves; vessel shells, heads, and welds (3.1.1-2) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) and environmental effects addressed for Class 1 components Yes Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| Steel; stainless steel; steel with Ni
| |
| -alloy or stainless steel cladding; Ni
| |
| -alloy RCPB piping, piping components, and piping elements exposed to reactor coolant (3.1.1
| |
| -3) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) and environmental effects addressed for Class 1 components Yes Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation
| |
| | |
| Aging Management Review Results 3-270 Steel pump and valve closure bolting (3.1.1-4) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) and Code limits checked for allowable cycles (less than 7,000 cycles) of thermal stress range Yes Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| Stainless steel and Ni-alloy RVI components (3.1.1-5) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c)
| |
| Yes TLAA, evaluated in accordance with 10 CFR 54.21(c)
| |
| Fatigue is a TLAA (See SER Section 3.1.2.2.1)
| |
| Ni-alloy tubes and sleeves in a reactor coolant and secondary feedwater/steam environment (3.1.1-6) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c)
| |
| Yes TLAA, evaluated in accordance with 10 CFR 54.21(c)
| |
| Fatigue is a TLAA (See SER Section 3.1.2.2.1)
| |
| Steel and stainless steel RCPB closure bolting, head closure studs, support skirts and attachment welds; pressurizer relief tank components; steam generator components; piping and components external surfaces and bolting (3.1.1
| |
| -7) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c)
| |
| Yes TLAA, evaluated in accordance with 10 CFR 54.21(c)
| |
| Fatigue is a TLAA (See SER Section 3.1.2.2.1)
| |
| Steel; stainless steel; Ni-alloy RCPB piping, piping components, piping elements; flanges; nozzles and safe ends; pressurizer vessel shell heads and welds; heater sheaths and sleeves; penetrations; thermal sleeves (3.1.1
| |
| -8) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) and environmental effects addressed for Class 1 components Yes TLAA, evaluated in accordance with 10 CFR 54.21(c) and environmental effects addressed for Class 1 components Fatigue is a TLAA (See SER Section 3.1.2.2.1)
| |
| Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation
| |
| | |
| Aging Management Review Results 3-271 Steel; stainless steel; steel with Ni
| |
| -alloy or stainless steel cladding; Ni
| |
| -alloy reactor vessel components: flanges; nozzles; penetrations; pressure housings; safe ends; thermal sleeves; vessel shells, heads, and welds (3.1.1-9) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) and environmental effects addressed for Class 1 components Yes TLAA, evaluated in accordance with 10 CFR 54.21(c) and environmental effects addressed for Class 1 components Fatigue is a TLAA (See SER Section 3.1.2.2.1)
| |
| Steel; stainless steel; steel with Ni
| |
| -alloy or stainless steel cladding; Ni
| |
| -alloy steam generator components (flanges; penetrations; nozzles; safe ends, lower heads, and welds) (3.1.1
| |
| -10) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) and environmental effects addressed for Class 1 components Yes TLAA, evaluated in accordance with 10 CFR 54.21(c) and environmental effects addressed for Class 1 components Fatigue is a TLAA (See SER Section 3.1.2.2.1)
| |
| Steel top head enclosure (without cladding) and top head nozzles (vent, top head spray, or reactor core isolation cooling, and spare) exposed to reactor coolant (3.1.1
| |
| -11) Loss of material due to general, pitting, and crevice corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| Steel steam generator shell assembly exposed to secondary feedwater and steam (3.1.1-12) Loss of material due to general, pitting, and crevice corrosion Water Chemistry and One-Time Inspection Yes Once-through steam generator (OTSG) only Applicable to OTSGs, therefore, not applicable to Seabrook (See SER Section 3.1.2.1.1)
| |
| Steel and stainless steel isolation condenser components exposed to reactor coolant (3.1.1-13) Loss of material due to general (steel only), pitting, and crevice corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| Stainless steel; Ni alloy; steel with Ni
| |
| - alloy or stainless steel cladding RV flanges, nozzles, penetrations, safe ends, vessel shells, heads, and welds (3.1.1-14) Loss of material due to pitting and crevice corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| | |
| Aging Management Review Results 3-272 Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Stainless steel; steel with Ni-alloy or stainless steel cladding; Ni
| |
| -alloy RCPB components exposed to reactor coolant (3.1.1
| |
| -15) Loss of material due to pitting and crevice corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| Steel steam generator upper and lower shell and transition cone exposed to secondary feedwater and steam (3.1.1-16) Loss of material due to general, pitting, and crevice corrosion ISI (IWB, IWC, and IWD) and Water Chemistry.
| |
| For Westinghouse Model 44 and 51 steam generators, if general and pitting corrosion of the shell is known to exist, additional inspection procedures are to be developed.
| |
| Yes ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program; Water Chemistry Program; and Steam Generator Tube Integrity Program Consistent with the GALL Report (See SER Section 3.1.2.2.2)
| |
| Steel (with or without stainless steel cladding) RV beltline shell, nozzles, and welds (3.1.1-17) Loss of fracture toughness due to neutron irradiation embrittlement TLAA, evaluated in accordance with Appendix G of 10 CFR Part 50 and RG 1.99. The applicant may choose to demonstrate that the materials of the nozzles are not controlling for the TLAA evaluations.
| |
| Yes TLAA, evaluated in accordance with 10 CFR 54.21(c), Appendix G of 10 CFR Part 50, and RG 1.99 Loss of fracture toughness due to neutron irradiation is a TLAA (See SER Section 3.1.2.2.3)
| |
| Steel (with or without stainless steel cladding) RV beltline shell, nozzles, and welds; SI nozzles (3.1.1-18) Loss of fracture toughness due to neutron irradiation embrittlement Reactor Vessel Surveillance Yes RV Surveillance Program Consistent with the GALL Report (See SER Section 3.1.2.2.3)
| |
| Stainless steel and Ni-alloy top head enclosure vessel flange leak detection line (3.1.1-19) Cracking due to SCC and IGSCC A plant-specific AMP is to be evaluated.
| |
| Yes Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| | |
| Aging Management Review Results 3-273 Stainless steel isolation condenser components exposed to reactor coolant (3.1.1-20) Cracking due to SCC and IGSCC ISI (IWB, IWC, and IWD), Water Chemistry, and plant-specific verification program Yes Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation RV shell fabricated of SA508-Cl 2 forgings clad with stainless steel using a high
| |
| - heat-input welding process (3.1.1-21) Crack growth due to cyclic loading TLAA Yes Not Applicable
| |
| - Seabrook's RV shell is not fabricated of SA508-Cl 2 forgings clad with stainless steel using a high
| |
| -heat- input welding process. Not applicable to Seabrook (See SER Section 3.1.2.2.5)
| |
| Stainless steel and Ni-alloy RVI components exposed to reactor coolant and neutron flux (3.1.1
| |
| -22) Loss of fracture toughness due to neutron irradiation embrittlement, void swelling UFSAR supplement commitment to participate in industry RVI aging programs; implement applicable results; and submit for staff approval, greater than 24 months before the period of extended operation, an RVI inspection plan based on industry recommendation.
| |
| No PWR Vessel Internals Program Consistent with the GALL Report (See SER Section 3.1.2.2.6)
| |
| Stainless steel reactor vessel closure head flange leak detection line and bottom
| |
| -mounted instrument guide tubes (3.1.1
| |
| -23) Cracking due to SCC A plant-specific AMP is to be evaluated.
| |
| Yes ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program Consistent with the GALL Report (See SER Section 3.1.2.2.7)
| |
| Class 1 CASS piping, piping components, and piping elements exposed to reactor coolant (3.1.1
| |
| -24) Cracking due to SCC Water Chemistry and, for CASS components that do not meet the NUREG-0313 guidelines, a plant
| |
| -specific AMP Yes ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program, and Water Chemistry Program Consistent with the GALL Report (See SER Section 3.1.2.2.7)
| |
| | |
| Aging Management Review Results 3-274 Stainless steel jet pump sensing line (3.1.1-25) Cracking due to cyclic loading A plant-specific AMP is to be evaluated.
| |
| Yes Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| Steel and stainless steel isolation condenser components exposed to reactor coolant (3.1.1-26) Cracking due to cyclic loading ISI (IWB, IWC, and IWD) and plant
| |
| -specific verification program Yes Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Stainless steel and Ni
| |
| -alloy RVI screws, bolts, tie rods, and hold down springs (3.1.1-27) Loss of preload due to stress relaxation UFSAR supplement commitment to: participate in industry RVI aging programs; implement applicable results; and (3) submit for staff approval, greater than 24 months before the period of extended operation, an RVI inspection plan based on industry recommendation.
| |
| No PWR Vessel Internals Program Consistent with the GALL Report (See SER Section 3.1.2.2.9)
| |
| Steel steam generator feedwater impingement plate and support exposed to secondary feedwater (3.1.1
| |
| -28) Loss of material due to erosion A plant-specific AMP is to be evaluated.
| |
| Yes Not applicable to Seabrook Not applicable to Seabrook (See SER Section 3.1.2.2.10)
| |
| Stainless steel steam dryers exposed to reactor coolant (3.1.1-29) Cracking due to flow-induced vibration A plant-specific AMP is to be evaluated.
| |
| Yes Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| | |
| Aging Management Review Results 3-275 Stainless steel RVI components (e.g., upper internals assembly, rod cluster control assembly guide tube assemblies, baffle/former assembly, lower internal assembly, shroud assemblies, plenum cover and plenum cylinder, upper grid assembly, control rod guide tube assembly, core support shield assembly, core barrel assembly, lower grid assembly, flow distributor assembly, thermal shield, instrumentation support structures)
| |
| (3.1.1-30) Cracking due to SCC and IASCC Water Chemistry and UFSAR supplement commitment to: participate in industry, RVI aging programs; implement applicable results; and (3) submit for staff approval, greater than 24 months before the period of extended operation, an RVI inspection plan based on industry recommendation.
| |
| No PWR Vessel Internals and Water Chemistry programs Consistent with the GALL Report (See SER Section 3.1.2.2.12)
| |
| Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Ni alloy and steel with Ni-alloy cladding piping, piping component, piping elements, penetrations, nozzles, safe ends, and welds (other than RV head); pressurizer heater sheaths, sleeves, diaphragm plate, manways, and flanges; core support pads/core guide lugs (3.1.1-31) Cracking due to PWSCC ISI (IWB, IWC, and IWD) and Water Chemistry and UFSAR supplement commitment to implement applicable plant commitments to NRC Orders, bulletins, and GLs associated with Ni alloys and staff
| |
| - accepted industry guidelines.
| |
| No ASME Code Section XI ISI Subsections IWB, IWC, and IWD Program, Nickel-Alloy Nozzles and Penetrations Program, and the Water Chemistry Program Consistent with the GALL Report (See SER Section 3.1.2.2.13)
| |
| Steel steam generator feedwater inlet ring and supports (3.1.1
| |
| -32) Wall thinning due to flow
| |
| - accelerate d corrosion A plant-specific AMP is to be evaluated.
| |
| Yes Steam Generator Tube Integrity Program Consistent with GALL Report (See SER Section 3.1.2.2.14)
| |
| | |
| Aging Management Review Results 3-276 Stainless steel and Ni
| |
| -alloy RVI components (3.1.1-33) Changes in dimensions due to void swelling UFSAR supplement commitment to participate in industry RVI aging programs; implement applicable results; and submit for staff approval, greater than 24 months before the period of extended operation, an RVI inspection plan based on industry recommendation.
| |
| No PWR Vessel Internals Program Consistent with the GALL Report (See SER Section 3.1.2.2.15)
| |
| Stainless steel and Ni-alloy reactor control rod drive (CRD) head penetration pressure housings (3.1.1
| |
| -34) Cracking due to SCC and PWSCC ISI (IWB, IWC, and IWD) and Water Chemistry.
| |
| For Ni alloy, UFSAR supplement commitment to implement applicable plant commitments to NRC Orders, bulletins, and GLs associated with Ni alloys and staff
| |
| - accepted industry guidelines.
| |
| No ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program and Water Chemistry Program Consistent with the GALL Report (See SER Section 3.1.2.2.16)
| |
| Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Steel with stainless steel or Ni
| |
| -alloy cladding primary side components; steam generator upper and lower heads; tubesheets; and tube
| |
| -to-tubesheet welds (3.1.1-35) Cracking due to SCC and PWSCC ISI (IWB, IWC, and IWD) and Water Chemistry.
| |
| For Ni alloy, UFSAR supplement commitment to implement applicable plant commitments to NRC Orders, bulletins, and GLs associated with Ni alloys and staff
| |
| - accepted industry guidelines.
| |
| No Submit plant
| |
| -specific AMP to manage tube-tubesheet welds at least 24 months prior to the period of extended operation (Commitment 54)
| |
| Applicable to OTSGs; therefore, not applicable to Seabrook except for tube-to-tubesheet welds between Ni
| |
| -alloy cladding and Ni-alloy tubes in the steam generator (see SER Section 3.1.2.2.16)
| |
| | |
| Aging Management Review Results 3-277 Ni-alloy, stainless steel pressurizer spray head (3.1.1
| |
| -36) Cracking due to SCC and PWSCC Water Chemistry and One-Time Inspection. For Ni-alloy welded spray heads, provide commitment in UFSAR supplement to submit AMP delineating commitments to NRC Orders, bulletins, or GLs that inspect stipulated components for cracking of wetted surfaces.
| |
| No One-Time Inspection and Water Chemistry Programs Consistent with the GALL Report (See SER Section 3.1.2.2.16)
| |
| Stainless steel and Ni
| |
| -alloy RVI components (e.g., upper internals assembly, rod cluster control assembly guide tube assemblies, lower internal assembly, control element assembly (CEA) shroud assemblies, core shroud assembly, core support shield assembly, core barrel assembly, lower grid assembly, flow distributor assembly)
| |
| (3.1.1-37) Cracking due to SCC, PWSCC, and IASCC Water Chemistry and UFSAR supplement commitment to participate in industry RVI aging programs; implement applicable results; and submit for staff approval, greater than 24 months before the period of extended operation, an RVI inspection plan based on industry recommendation.
| |
| No The PWR Vessel Internals Program and the Water Chemistry Program, including Commitment No. 01 Consistent with the GALL Report (See SER Section 3.1.2.2.17)
| |
| Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Steel (with or without stainless steel cladding) CRD return line nozzles exposed to reactor coolant (3.1.1-38) Cracking due to cyclic loading BWR CRD Return Line Nozzle No Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| Steel (with or without stainless steel cladding) feedwater nozzles exposed to reactor coolant (3.1.1-39) Cracking due to cyclic loading BWR Feedwater Nozzle No Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| | |
| Aging Management Review Results 3-278 Stainless steel and Ni
| |
| -alloy penetrations for CRD stub tubes instrumentation, jet pump instrumentation, standby liquid control, flux monitor, and drain line exposed to reactor coolant (3.1.1-40) Cracking due to SCC, IGSCC, and cyclic loading BWR Penetrations and Water Chemistry No Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| Stainless steel and Ni-alloy piping, piping components, and nominal pipe size (NPS); nozzle safe ends and associated welds (3.1.1-41) Cracking due to SCC and IGSCC BWR SCC and Water Chemistry No Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| Stainless steel and Ni-alloy vessel shell attachment welds exposed to reactor coolant (3.1.1
| |
| -42) Cracking due to SCC and IGSCC BWR Vessel ID Attachment Welds and Water Chemistry No Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| Stainless steel fuel supports and CRD assemblies and CRD housing exposed to reactor coolant (3.1.1-43) Cracking due to SCC and IGSCC BWR Vessel Internals and Water Chemistry No Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| Stainless steel and Ni-alloy core shroud, core plate, core plate bolts, support structure, top guide, core spray lines, spargers, jet pump assemblies, CRD housing, and nuclear instrumentation guide tubes (3.1.1
| |
| -44) Cracking due to SCC, IGSCC, and IASCC BWR Vessel Internals and Water Chemistry No Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Steel piping, piping components, and piping elements exposed to reactor coolant (3.1.1
| |
| -45) Wall thinning due to flow
| |
| - accelerate d corrosion Flow-Accelerated Corrosion No Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| | |
| Aging Management Review Results 3-279 Ni-alloy core shroud and core plate access hole cover (mechanical covers)
| |
| (3.1.1-46) Cracking due to SCC, IGSCC, and IASCC ISI (IWB, IWC, and IWD), and Water Chemistry No Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| Stainless steel and Ni-alloy RVIs exposed to reactor coolant (3.1.1
| |
| -47) Loss of material due to pitting and crevice corrosion ISI (IWB, IWC, and IWD) and Water Chemistry No Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| Steel and stainless steel Class 1 piping, fittings, and branch connections reactor coolant (3.1.1-48) Cracking due to SCC, IGSCC (for stainless steel only), and thermal and mechanical loading ISI (IWB, IWC, and IWD) Water chemistry, and One-Time Inspection of ASME Code Class 1 Small- Bore Piping No Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| Ni-alloy core shroud and core plate access hole cover (welded covers)
| |
| (3.1.1-49) Cracking due to SCC, IGSCC, and IASCC ISI (IWB, IWC, and IWD), Water Chemistry, and, for BWRs with a crevice in the access hole covers, augmented inspection using UT or other demonstrated acceptable inspection of the access hole cover welds No Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| High-strength low
| |
| - alloy steel top head closure studs and nuts exposed to air with reactor coolant leakage (3.1.1-50) Cracking due to SCC and IGSCC Reactor Head Closure Studs No Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| CASS jet pump assembly castings and orificed fuel support (3.1.1
| |
| -51) Loss of fracture toughness due to thermal aging and neutron irradiation embrittlement Thermal Aging and Neutron Irradiation Embrittlement of CASS No Not applicable Not applicable to PWRs (See SER Section 3.1.2.1.1)
| |
| Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation
| |
| | |
| Aging Management Review Results 3-280 Steel and stainless steel RCPB pump and valve closure bolting, manway and holding bolting, flange bolting, and closure bolting in high-pressure and high-temperature systems (3.1.1
| |
| -52) Cracking due to SCC, loss of material due to wear, loss of preload due to thermal effects, gasket creep, and self-loosening Bolting Integrity No Bolting Integrity Program Consistent with the GALL Report Steel piping, piping components, and piping elements exposed to closed
| |
| - cycle cooling water (3.1.1-53) Loss of material due to general, pitting, and crevice corrosion Closed-Cycle Cooling Water System No Closed-Cycle Cooling Water System Program Consistent with the GALL Report Copper-alloy piping, piping components, and piping elements exposed to closed
| |
| - cycle cooling water (3.1.1-54) Loss of material due to pitting, crevice, and galvanic corrosion Closed-Cycle Cooling Water System No Not applicable Not applicable to Seabrook (See SER Section 3.1.2.1.1)
| |
| CASS Class 1 pump casings and valve bodies and bonnets exposed to reactor coolant > 482 °F (250 °C) (3.1.1-55) Loss of fracture toughness due to thermal aging embrittlement ISI (IWB, IWC, and IWD). Thermal aging susceptibility screening is not necessary, ISI requirements are sufficient for managing these aging effects.
| |
| ASME Code Case N-481 also provides an alternative for pump casings.
| |
| No ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program Consistent with the GALL Report Copper-alloy > 15% Zn piping, piping components, and piping elements exposed to closed
| |
| - cycle cooling water (3.1.1-56) Loss of material due to selective leaching Selective Leaching of Materials No Not applicable Not applicable to Seabrook (See SER Section 3.1.2.1.1)
| |
| CASS Class 1 piping, piping components, and piping elements and CRD pressure housings exposed to reactor coolant > 482 °F (250 °C)
| |
| (3.1.1-57) Loss of fracture toughness due to thermal aging embrittlement Thermal Aging Embrittlement of CASS No Not applicable Not applicable to Seabrook (See SER Section 3.1.2.1.1)
| |
| | |
| Aging Management Review Results 3-281 Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Steel RCPB external surfaces exposed to air with borated water leakage (3.1.1
| |
| -58) Loss of material due to boric acid corrosion Boric Acid Corrosion No Boric Acid Corrosion Program Consistent with the GALL Report Steel steam generator steam nozzle and safe end, feedwater nozzle and safe end, auxiliary feedwater nozzles and safe ends exposed to secondary feedwater/steam (3.1.1-59) Wall thinning due to flow
| |
| - accelerate d corrosion Flow-Accelerated Corrosion No Flow-Accelerated Corrosion Program Consistent with the GALL Report Stainless steel flux thimble tubes (with or without chrome plating) (3.1.1
| |
| -60) Loss of material due to wear Flux Thimble Tube Inspection No Not applicable Not applicable to Seabrook (See SER Section 3.1.2.1.1)
| |
| Stainless steel and steel pressurizer integral support exposed to air with metal temperature up to 550 °F (288 °C)
| |
| (3.1.1-61) Cracking due to cyclic loading ISI (IWB, IWC, and IWD) No ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program Consistent with the GALL Report Stainless steel, steel with stainless steel cladding RCS cold leg, hot leg, surge line, and spray line piping and fittings exposed to reactor coolant (3.1.1
| |
| -62) Cracking due to cyclic loading ISI (IWB, IWC, and IWD) No ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program Consistent with the GALL Report Steel reactor vessel flange and stainless steel and Ni
| |
| -alloy RVIs exposed to reactor coolant (e.g., upper and lower internals assembly, CEA shroud assembly, core support barrel, upper grid assembly, core support shield assembly, and lower grid assembly)
| |
| (3.1.1-63) Loss of material due to wear ISI (IWB, IWC, and IWD) No ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program Consistent with the GALL Report
| |
| | |
| Aging Management Review Results 3-282 Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Stainless steel and steel with stainless steel or Ni
| |
| -alloy cladding pressurizer components (3.1.1-64) Cracking due to SCC and PWSCC ISI (IWB, IWC, and IWD) and Water Chemistry No ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program and Water Chemistry Program Consistent with the GALL Report Ni-alloy reactor vessel upper head and CRD penetration nozzles, instrument tubes, head vent pipe (top head), and welds (3.1.1-65) Cracking due to PWSCC ISI (IWB, IWC, and IWD) and Water Chemistry and Ni
| |
| -Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors No ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program, Nickel-Alloy Penetration Nozzles Welded to the Upper RV Closure Heads of PWRs Program, and Water Chemistry Program Consistent with the GALL Report Steel steam generator secondary manways and handholds (cover only) exposed to air with leaking secondary-side water or steam or both (3.1.1-66) Loss of material due to erosion ISI (IWB, IWC, and IWD) for Class 2 components No Not applicable Not applicable to Seabrook, applicable to OTSGs (See SER Section 3.1.2.1.1)
| |
| Steel with stainless steel or Ni
| |
| -alloy cladding or stainless steel pressurizer components exposed to reactor coolant (3.1.1-67) Cracking due to cyclic loading ISI (IWB, IWC, and IWD) and Water Chemistry No ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program and Water Chemistry Program Consistent with the GALL Report
| |
| | |
| Aging Management Review Results 3-283 Stainless steel; steel with stainless steel cladding Class 1 piping, fittings, pump casings, valve bodies, nozzles, safe ends, manways, flanges, CRD housing; pressurizer heater sheaths, sleeves, diaphragm plate; pressurizer relief tank components, RCS cold leg, hot leg, surge line, and spray line piping and fittings (3.1.1-68) Cracking due to SCC ISI (IWB, IWC, and IWD) and Water Chemistry No ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program, and Water Chemistry Program Consistent with the GALL Report Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Stainless steel, Ni
| |
| - alloy SI nozzles, safe ends, and associated welds and buttering exposed to reactor coolant (3.1.1-69) Cracking due to SCC and PWSCC ISI (IWB, IWC, and IWD) and Water Chemistry No ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program and Water Chemistry Program Consistent with the GALL Report (See SER Section 3.1.2.1.2)
| |
| Stainless steel; steel with stainless steel cladding Class 1 piping, fittings, and branch connections reactor coolant (3.1.1-70) Cracking due to SCC and thermal and mechanical loading ISI (IWB, IWC, and IWD), Water Chemistry, and One-Time Inspection of ASME Code Class 1 Small- Bore Piping No ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program, Water Chemistry Program, and One-Time Inspection of ASME Code Class 1 Small- Bore Piping Program Consistent with the GALL Report High-strength low
| |
| - alloy steel closure head stud assembly exposed to air with reactor coolant leakage (3.1.1-71) Cracking due to SCC and loss of material due to wear Reactor Head Closure Studs No Reactor Head Closure Studs Program Consistent with the GALL Report
| |
| | |
| Aging Management Review Results 3-284 Ni-alloy steam generator tubes and sleeves exposed to secondary feedwater/steam (3.1.1-72) Cracking due to outside- diamete r stress corrosion cracking and intergranular attack and loss of material due to fretting and wear Steam Generator Tube Integrity and Water Chemistry No Steam Generator Tube Integrity Program and Water Chemistry Program Consistent with the GALL Report Ni-alloy steam generator tubes, repair sleeves, and tube plugs exposed to reactor coolant (3.1.1-73) Cracking due to PWSCC Steam Generator Tube Integrity and Water Chemistry No Steam Generator Tube Integrity Program and Water Chemistry Program Consistent with the GALL Report Chrome plated steel, stainless steel, Ni
| |
| - alloy steam generator anti
| |
| -vibration bars exposed to secondary feedwater/steam (3.1.1-74) Cracking due to SCC and loss of material due to crevice corrosion and fretting Steam Generator Tube Integrity and Water Chemistry No Steam Generator Tube Integrity Program and Water Chemistry Program Consistent with the GALL Report Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Ni-alloy OTSG
| |
| -tubes exposed to secondary feedwater/steam (3.1.1-75) Denting due to corrosion of carbon steel tube support plate Steam Generator Tube Integrity and Water Chemistry No Not applicable Not applicable to Seabrook, applicable to OTSGs (See SER Section 3.1.2.1.1)
| |
| Steel steam generator tube support plate and tube bundle wrapper exposed to secondary feedwater/steam (3.1.1-76) Loss of material due to erosion, general, pitting, and crevice corrosion and ligament cracking due to corrosion Steam Generator Tube Integrity and Water Chemistry No Steam Generator Tube Integrity Program and Water Chemistry Program Consistent with the GALL Report. Ligament cracking due to corrosion is not applicable to the tube support plates since they are stainless stee l (See SER Section 3.1.2.1.1)
| |
| Ni-alloy steam generator tubes and sleeves exposed to phosphate chemistry in secondary feedwater/steam (3.1.1-77) Loss of material due to wastage and pitting corrosion Steam Generator Tube Integrity and Water Chemistry No Not applicable Not applicable (See SER Section 3.1.2.1.1)
| |
| | |
| Aging Management Review Results 3-285 Steel steam generator tube support lattice bars exposed to secondary feedwater/steam (3.1.1-78) Wall thinning due to flow
| |
| - accelerate d corrosion Steam Generator Tube Integrity and Water Chemistry No Not applicable Not applicable (See SER Section 3.1.2.1.1)
| |
| Ni-alloy steam generator tubes exposed to secondary feedwater/steam (3.1.1-79) Denting due to corrosion of steel tube support plate Steam Generator Tube Integrity and Water Chemistry. For plants that could experience denting at the upper support plates, evaluate potential for rapidly propagating cracks and then develop and take corrective actions consistent with Bulletin 88
| |
| -02. No Not applicable Not applicable (See SER Section 3.1.2.1.1)
| |
| CASS RVIs (e.g., upper internals assembly, lower internal assembly, CEA shroud assemblies, control rod guide tube assembly, core support shield assembly, lower grid assembly)
| |
| (3.1.1-80) Loss of fracture toughness due to thermal aging and neutron irradiation embrittlement Thermal Aging and Neutron Irradiation Embrittlement of CASS No Not applicable Not applicable (See SER Section 3.1.2.1.2)
| |
| Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Ni alloy or Ni
| |
| -alloy clad steam generator divider plate exposed to reactor coolant (3.1.1-81) Cracking due to PWSCC Water Chemistry No Water Chemistry Program and one
| |
| -time inspection of SG divider plates Consistent with the GALL Report (See SER Section 3.1.2.1)
| |
| Stainless steel steam generator primary side divider plate exposed to reactor coolant (3.1.1
| |
| -82) Cracking due to SCC Water Chemistry No Not applicable Not applicable to Seabrook, (See SER Section 3.1.2.1.1)
| |
| | |
| Aging Management Review Results 3-286 Stainless steel; steel with Ni-alloy or stainless steel cladding; Ni
| |
| -alloy RVIs and RCPB components exposed to reactor coolant (3.1.1-83) Loss of material due to pitting and crevice corrosion Water Chemistry No Water Chemistry Program Consistent with the GALL Report Ni-alloy steam generator components, such as secondary-side nozzles (vent, drain, and instrumentation) exposed to secondary feedwater/steam (3.1.1-84) Cracking due to SCC Water Chemistry and One-Time Inspection or ISI (IWB, IWC, and IWD) No Not applicable Not applicable to Seabrook, applicable to OTSGs (See SER Section 3.1.2.1.1)
| |
| Ni-alloy piping, piping components, and piping elements exposed to air
| |
| -indoor uncontrolled (external)
| |
| (3.1.1-85) None None No None Consistent with the GALL Report Stainless steel piping, piping components, and piping elements exposed to air
| |
| -indoor uncontrolled (external); air with borated water leakage; concrete; gas (3.1.1-86) None None No None Consistent with the GALL Report Steel piping, piping components, and piping elements in concrete (3.1.1
| |
| -87) None None No Not applicable Not applicable to Seabrook (See SER Section 3.1.2.1.1)
| |
| The staff's review of the RCS component groups followed one of several approaches. One approach, documented in SER Section 3.1.2.1, discusses the staff's review of AMR results for components that the applicant indicated are consistent with the GALL Report and require no further evaluation. Another approach, documented in SER Section 3.1.2.2, discusses the staff's review of AMR results for components that the applicant indicated are consistent with the GALL Report and for which further evaluation is recommended. A third approach, documented in SER Section 3.1.2.3, discusses the staff's review of AMR results for components that the applicant indicated are not consistent with or not addressed in the GALL Report. The staff's review of AMPs credited to manage or monitor aging effects of the RCS components is documented in SER Section 3.0.3.
| |
| | |
| Aging Management Review Results 3-287 3.1.2.1 Aging Management Review Results That Are Consistent with the GALL Report LRA Section 3.1.2.1 identifies the materials, environments, AERMs, and the following programs that manage aging effects for the RCS, reactor vessel, RVIs, and steam generator components:
| |
| * ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program
| |
| * Bolting Integrity Program
| |
| * Boric Acid Corrosion Program
| |
| * Closed-Cycle Cooling Water System Program
| |
| * External Surfaces Monitoring Program
| |
| * Flow-Accelerated Corrosion Program
| |
| * Nickel-Alloy Nozzles and Penetrations Program
| |
| * Nickel-Alloy Penetration Nozzles Welded to the Upper RV Closure Heads of PWRs Program
| |
| * One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program
| |
| * One-Time Inspection Program
| |
| * PWR Vessel Internals Program
| |
| * Reactor Head Closure Studs Program
| |
| * Reactor Vessel Surveillance Program
| |
| * Steam Generator Tube Integrity Program
| |
| * Water Chemistry Program LRA Tables 3.1.2
| |
| -1 through 3.1.2
| |
| -4 summarize the results of AMRs for the RCS, reactor vessel, RVIs, and steam generator components and indicate AMRs claimed to be consistent with the GALL Report.
| |
| For component groups evaluated in the GALL Report for which the applicant claimed consistency and for which the GALL Report does not recommend further evaluation, the staff performed an audit and review to determine if the plant
| |
| -specific components in these GALL Report component groups were bounded by the GALL Report evaluation.
| |
| The applicant provided a note for each AMR item describing how the information in the tables aligns with the information in the GALL Report. The staff reviewed those AMRs with LRA Notes A-E, which indicate how the AMR was consistent with the GALL Report.
| |
| Note A indicates that the AMR item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. The staff reviewed these items to verify consistency with the GALL Report and the validity of the AMR for the site
| |
| -specific conditions.
| |
| Note B indicates that the AMR item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff reviewed these items to verify consistency with the GALL Report and to ensure that it had reviewed and accepted the identified exceptions to the Aging Management Review Results 3-288 GALL Report AMPs. The staff also determined whether the AMP identified by the applicant was consistent with the AMP identified in the GALL Report and whether the AMR was valid for the site-specific conditions.
| |
| Note C indicates that the component for the AMR item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the AMP identified by the GALL Report. This note indicates that the applicant was unable to find a listing of some system components in the GALL Report; however, the applicant identified a different component in the GALL Report that had the same material, environment, aging effect, and AMP as the component under review. The staff reviewed these items to verify consistency with the GALL Report. The staff also determined whether the AMR item of the different component applied to the component under review and whether the AMR was valid for the site
| |
| -specific conditions.
| |
| Note D indicates that the component for the AMR item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff reviewed these items to verify consistency with the GALL Report. The staff confirmed whether the AMR item of the different component was applicable to the component under review and whether the exceptions to the GALL Report AMPs was reviewed and accepted by the staff. The staff also determined whether the AMP identified by the applicant was consistent with the AMP identified in the GALL Report and whether the AMR was valid for the site
| |
| -specific conditions.
| |
| Note E indicates that the AMR item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited. The staff reviewed these items to verify consistency with the GALL Report and determined whether the identified AMP would manage the aging effect consistent with the AMP identified in the GALL Report and whether the AMR was valid for the site
| |
| -specific conditions.
| |
| The staff reviewed the information in the LRA. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The staff's evaluation follows.
| |
| LRA Table 3.1.1, item 3.1.1
| |
| -81, addresses nickel alloy or nickel
| |
| -alloy clad steam generator divider plates exposed to reactor coolant, which are being managed for cracking due to primary water stress corrosion cracking (PWSCC). The LRA credits the Water Chemistry Program to manage the aging effect. The GALL Report recommends GALL Report AMP XI.M2, "Water Chemistry," to ensure that this aging effect is adequately managed.
| |
| In its review of components associated with item 3.1.1
| |
| -81, for which the applicant cited generic Note A, the staff noted that, subsequent to the publication date of GALL Report, Revision 1 (September 2005), foreign operating experience in steam generators with a similar design to that of the applicant's steam generators found cracking due to PWSCC in the steam generator divider plate assemblies made of Alloy 600, even with proper primary water chemistry. Specifically, cracks were detected in the stub runner, very close to the tubesheet/stub runner weld and with depths of almost a third of the divider plate thickness. Therefore, the staff noted that the Water Chemistry Program, alone, may not be effective in managing cracking due to PWSCC in steam generator divider plate assemblies.
| |
| | |
| Aging Management Review Results 3-289 The staff further noted that, based on the foreign steam generator divider plate experience, the domestic PWR industry has issued technical studies, such as EPRI Report 1014982, "Divider Plate Cracking in Steam Generators
| |
| -Results of Phase 1: Analysis of Primary Water Stress Corrosion Cracking and Mechanical Fatigue in the Alloy 600 Stub Runner to Divider Plate Weld Material," June 2007, to address cracking due to PWSCC for nickel
| |
| -alloy divider plates and potential for propagation of divider plate cracks into other adjacent components.
| |
| By letter dated December 14, 2010, the staff issued RAI B.2.1.10
| |
| -2, requesting that the applicant discuss the materials of construction for its steam generator divider plate assemblies and the susceptibility of its divider plate assemblies to cracking. The staff also asked the applicant to describe an inspection program to ensure that there are no cracks that could propagate into and challenge the integrity of other components that are part of the RCPB (e.g., tube sheet and channel head).
| |
| Details of the applicant's response to RAI B.2.1.10
| |
| -2 and the staff's evaluation of that response are documented in SER Section 3.0.3.2.2. In its response, the applicant stated that it has Westinghouse Model F steam generators, and the steam generators' divider plates and weld materials are Inconel (ASME
| |
| -SB-168) Alloy 600/82/182. The applicant further stated that it will perform an inspection of each steam generator, including a one
| |
| -time inspection of the divider plate assemblies, prior to entering the period of extended operation and that any evidence of divider plate cracking will be documented and evaluated under the corrective action program. The applicant also stated that the inspection techniques used will be capable of detecting PWSCC in the steam generator divider plate assemblies and their associated welds. The applicant committed (Commitment 55) that, within 5 years prior to entering the period of extended operation, it will perform inspections of each steam generator, including the one
| |
| -time inspection of divider plate assemblies.
| |
| The staff's evaluation of the applicant's response to RAI B.2.1.10
| |
| -2 is documented in SE R Section 3.0.3.2.2, Steam Generator Tube Integrity Program. Open Item OI 3.0.3.2.2
| |
| -1 was identified for the applicant to provide additional information regarding its one
| |
| -time inspection of the divider plate assembly in its UFSAR supplement. Resolution for OI 3.0.3.2.2
| |
| -1 is documented in Section 3.0.3.2.2.
| |
| By letter dated October 2, 2014, the applicant submitted an annual update to LRA Table 3.1.2
| |
| -1, to add AMR items for incore detector assembly restraints. The staff reviewed these AMR items associated with LRA Table 3.1.1, item 3.1.1
| |
| -86, and confirmed that these AMR items are consistent with the GALL Report recommendations.
| |
| 3.1.2.1.1 Aging Management Review Results Identified as Not Applicable Based on its initial review, the staff identified several items of LRA Table 3.1.1 in which the applicant stated the items were not applicable to Seabrook. This subsection discusses the evaluation of those items.
| |
| LRA Table 3.1.1, items 3.1.1
| |
| -1, 3.1.1-2, 3.1.1-3, 3.1.1-4, 3.1.1-11, 3.1.1-13, 3.1.1-14, 3.1.1-15, 3.1.1-19, 3.1.1-20, 3.1.1-25, 3.1.1-26, 3.1.1-29, 3.1.1-38, 3.1.1-39, 3.1.1-40, 3.1.1-41, 3.1.1-42, 3.1.1-43, 3.1.1-44, 3.1.1-45, 3.1.1-46, 3.1.1-47, 3.1.1-48, 3.1.1-49, 3.1.1-50, and 3.1.1
| |
| -51 discuss the applicant's determination on GALL Report AMR items that are applicable only to BWR-designed reactors. In the applicant AMR discussions for these items, no additional information is provided. The staff confirmed that these AMR items in Table 1 of the GALL Aging Management Review Results 3-290 Report, Volume 1, are only applicable to BWR
| |
| -designed reactors and that Seabrook is a PWR with a dry ambient containment. Based on this determination, the staff finds that the applicant provided an acceptable basis for concluding AMR items 3.1.1
| |
| -1, 3.1.1-2, 3.1.1-3, 3.1.1-4, 3.1.1-11, 3.1.1-13, 3.1.1-14, 3.1.1-15, 3.1.1-19, 3.1.1-20, 3.1.1-25, 3.1.1-26, 3.1.1-29, 3.1.1-38, 3.1.1-39, 3.1.1-40, 3.1.1-41, 3.1.1-42, 3.1.1-43, 3.1.1-44, 3.1.1-45, 3.1.1-46, 3.1.1-47, 3.1.1-48, 3.1.1-49, 3.1.1-50, and 3.1.1
| |
| -51 in Table 1 of the GALL Report, Volume 1, are not applicable to Seabrook.
| |
| LRA Table 3.1.1, items 3.1.1
| |
| -12, 3.1.1-66, 3.1.1-75, and 3.1.1
| |
| -84 discuss the applicant's determination on GALL Report AMR items that are applicable only to once
| |
| -through steam generators (OTSGs). The staff confirmed that these AMR items in Table 1 of the GALL Report, Volume 1, are only applicable to OTSGs and confirmed, by reviewing various sections of the LRA and UFSAR, that Seabrook has recirculating steam generators. Based on this determination, the staff finds that the applicant provided an acceptable basis for concluding AMR items 12, 35, 66, 75, and 84 in Table 1 of the GALL Report, Volume 1, are not applicable to Seabrook.
| |
| LRA Table 3.1.1, item 3.1.1
| |
| -35 addresses cracking due to stress corrosion cracking (SCC) and PWSCC in steel with stainless steel or Ni
| |
| -alloy cladding primary side components and steam generator upper and lower heads, tubesheets, and tube
| |
| -to-tubesheet welds. The staff confirmed, with one exception noted below, that this AMR item in Table 1 of the GALL Report, Volume 1, is only applicable to OTSGs, and confirmed, by reviewing various sections of the LRA and the UFSAR, that Seabrook has recirculating steam generators. Based on this determination, the staff finds that the applicant provided an acceptable basis for concluding AMR item 35 in Table 1 of the GALL Report, Volume 1, is not applicable to Seabrook with one exception-the tube-to-tubesheet welds for the steam generators. This issue is discussed and resolved in SER Section 3.1.2.2.16.1.
| |
| LRA Table 3.1.1, item 3.1.1
| |
| -54 addresses the loss material due to pitting, crevice, and galvanic corrosion of copper
| |
| -alloy piping, piping components, and piping elements exposed to closed
| |
| -cycle cooling water. The applicant stated that these items are not applicable to Seabrook because there are no copper
| |
| -alloy components exposed to closed
| |
| -cycle cooling water in the RCS, RC, RVIs, or steam generator.
| |
| The staff reviewed the LRA and the UFSAR and concludes that the applicant does not have any AMR results that are applicable for this item.
| |
| LRA Table 3.1.1, item 3.1.1
| |
| -56 addresses copper
| |
| -alloy (with greater than 15
| |
| -percent Zn) piping, piping components, piping elements, and heat exchanger components exposed to closed
| |
| -cycle cooling water. The GALL Report recommends the use of GALL Report AMP XI.M33, "Selective Leaching of Materials," to manage loss of material due to selective leaching for this component group. The applicant stated that this item is not applicable because there are no RCS components fabricated from copper alloy greater than 15
| |
| -percent Zn and exposed to closed
| |
| -cycle cooling water.
| |
| The staff reviewed the LRA and the UFSAR and concludes that the applicant does not have any AMR results that are applicable for this item.
| |
| LRA Table 3.1.1, item 3.1.1
| |
| -57 describes the aging effect in cast austenitic stainless steel (CASS) Class 1 piping, piping components, piping elements, and CRD pressure housings Aging Management Review Results 3-291 exposed to reactor coolant greater than 482 °F (250 °C). The applicant stated that the RCS has fittings made of SA
| |
| -351 Grade CF8A material with service conditions greater than 482 °F. Additionally, the aging effect in the GALL Report for this material and environment combination is not applicable because the molybdenum and ferrite contents for these components are below the industry
| |
| -accepted thresholds for loss of fracture toughness due to thermal aging embrittlement.
| |
| The staff reviewed the LRA and the UFSAR and concludes that the applicant does not have any AMR results that are applicable for this item.
| |
| LRA Table 3.1.1, item 3.1.1
| |
| -60, addresses loss of material due to wear for stainless steel flux thimble tubes (with or without chrome plating) exposed to reactor coolant. The applicant stated that this item is not applicable because it uses a double
| |
| -concentric thimble tube design fabricated from wear
| |
| -resistant, seamless nickel
| |
| -alloy material (Inconel 600).
| |
| The staff noted that GALL Report AMR item IV.B2
| |
| -13 recommends GALL Report AMP XI.M37, "Flux Thimble Tube Inspection," to manage the loss of material due to wear for stainless steel flux thimble tubes (with or without chrome plating). However, the GALL Report does not include a generic AMR item for the management of loss of material due to wear in nickel
| |
| -alloy flux thimble tubes. The "detection of aging effects" program element in GALL Report AMP XI.M37 states that, for Westinghouse design flux thimble tubes, if design changes are made to use more wear-resistant thimble tube materials (e.g., chrome
| |
| -plated stainless steel), sufficient inspections will be conducted at an adequate inspection frequency for the new materials. In addition, the staff also noted that LRA Table 3.1.2
| |
| -3 includes an AMR item to manage cracking in the nickel-alloy flux thimble tubes. The applicant credited its PWR Vessel Internals Program and Water Chemistry Program to manage cracking. The applicant's PWR Vessel Internals Program is described in LRA Section B.2.1.7 and is based on recommendations in "Materials Reliability Program: Pressurized Water Reactor Internals Inspection and Evaluation Guidelines (MRP-227, Revision 0)." The staff reviewed MRP
| |
| -227, Revision 0, and noted that it does not include guidance for managing cracking of flux thimble tubes. By letter dated January 5, 2011, the staff issued RAI 3.1.1 01, requesting that the applicant justify not including an applicable AMR item to manage loss of material due to wear in the nickel-alloy flux thimble tubes. The staff also asked the applicant to justify why a Flux Thimble Tube Inspection Program is not credited to manage loss of material due to wear for these components.
| |
| In addition, the staff also issued RAI 3.1.1 02, by letter dated January 5, 2011, requesting that the applicant justify its crediting of the PWR Vessel Internals Program to manage cracking in flux thimble tubes, considering that MRP
| |
| -227, Revision 0 does not contain recommendations for managing cracking in Westinghouse
| |
| -design flux thimble tubes.
| |
| In its response to RAI 3.1.1-60-01, by letter dated February 3, 2011, the applicant stated that its design is unique and can accommodate both fixed and movable incore detectors housed, respectively, in the outer and inner tubes of the double
| |
| -concentric thimble tube design. Th e applicant also stated that since its Operating Cycle 5, the movable incore detectors have not been used and were placed into a lay
| |
| -up condition during RFO 7 (fall 2000). The applicant also stated that since RFO 7, as part of a design change, "Movable Incore Detector System Lay
| |
| -up," the seal table tubing between the inner calibration tubing and the isolation valves has been removed, and the inner calibration tubing has been capped. The applicant further stated that, Aging Management Review Results 3-292 based on the unique design features of the incore detector, the aging effects managed by GALL Report AMP XI.M37 do not apply. The staff found the applicant's response inadequate because, per the plant's licensing basis (License Amendment No. 27 (ADAMS Accession No. ML011870008)), the applicant is allowed and has the option to place the movable incore detectors back in service, putting the inner tubes in a condition that is susceptible to wear.
| |
| In its response to RAI 3.1.1 02, by letter dated February 3, 2011, the applicant stated that the design change has disconnected the movable detector and has installed a qualified pressure-retaining cap. The applicant further stated that flux thimble tubes do not have a license renewal
| |
| -intended RCPB function. For this reason, the applicant subsequently deleted the pressure boundary function for these thimble tubes from LRA Table 2.3.1
| |
| -3 and the AMR items on cracking of these thimble tubes from the scope of LRA Table 3.1.2
| |
| -3. The staff also found this response inadequate because it did not change the staff's previously stated concern that, per the plant's licensing basis, the applicant still has the option to place the movable incore detectors back in service, putting the inner tubes in a condition that is susceptible to wear as well as making it a pressure boundary.
| |
| By letter dated March 30, 2011, the staff issued an additional followup RAI 3.1.1 01/02 to request that the applicant further justify why an AMP is not required to manage loss of material due to wear of the inner tube flux thimble tubes during the period of extended operation if the movable detectors were placed back into service. In addition, the staff also asked the applicant to justify its deletion of the AMR items associated with cracking of the flux thimble tubes from LRA Table 3.1
| |
| .2-3. To resolve the staff's concern that the applicant could, in the future, place the movable incore detectors back in service, the applicant's response to followup RAI 3.1.1 01/02, dated April 22, 2011, provided a commitment to implementing measures prior to entering the period of extended operation to ensure that the movable detectors are not returned to service during the period of extended operation (Commitment 65). In addition, as part of its response, the applicant provided a drawing illustrating the design of the incore detector assembly. The applicant stated that when the incore detector assembly is inserted, the thimble housing tube (outer tube) provides the RCPB. The applicant also stated that the thimble calibration tube (inner tube), although considered an RCPB, is not in actual contact with reactor coolant. The applicant stated that the original fixed incore detector assemblies were not designed for the life of the plant, and, therefore, a replacement program was developed. For the replacement detector thimble assemblies, the inner tubes are solid from the seal table to below the core support plate. The applicant also stated that it plans to replace all 58 incore detector assemblies using the improved design. The applicant further stated that the plant's technical specifications (TS) require performance of an incore/excore comparison every 31 effective full power days (EFPD) when the power level is greater than 50 percent and an incore/excore calibration every 92 EFPD when power is greater than 75 percent.
| |
| Following review of the applicant's response to followup RAI 3.1.1 01/02, the staff needed further clarification as to where exactly the RCS pressure boundary is for the applicant's replacement detector assemblies and the original capped detector assemblies. Therefore, by letter dated October 7, 2011, the staff issued followup RAI 3.1.1 02, requesting that the applicant verify the RCS pressure boundary for the replacement and original capped incore detector assemblies.
| |
| | |
| Aging Management Review Results 3-293 In its response to followup RAI 3.1.1 02, dated November 2, 2011, the applicant stated that for the original incore detector assembly design, the RCS pressure boundary consists of the reactor vessel bottom instrument penetration, the incore instrument guide tube, the high pressure instrument connection, the portion of the calibration tube that extends above the high pressure instrument connection, and the pressure
| |
| -retaining cap. The applicant also stated that for replacement incore detector assembly design, the RCS pressure boundary consists of the reactor vessel bottom instrument penetration, the incore instrument guide tube, and the high pressure instrument connection. As part of its response, the applicant revised LRA Table 3.1.2
| |
| -1 and added three additional AMR Items under component type "Calibration Tube," on page 3.1
| |
| -44 of the LRA. In addition, as part of its response, the applicant also revised the boundary description on page 2.3
| |
| -5 of the LRA to reflect its response to followup RAI 3.1.1-60-02. Based on its review, the staff finds the applicant's response to followup RAI 3.1.1 02 acceptable because the applicant has revised LRA sections related to its flux thimble tubes in order to include portions of the incore detector assemblies that constitute the RCS pressure boundary and are subject to an AMR per 10 CFR 54.21(a)(1). The staff evaluated the applicant's revisions to LRA Tables 3.1.1 and 3.1.2
| |
| -1 and finds that for the portion of the applicant's flux thimble assemblies that constitute the RCS pressure boundary, there are no applicable aging effects. Specifically, the staff noted that two of the AMR items added correspond to NUREG
| |
| -1801, Volume 2, item IV.E
| |
| -1(RP-03), for which the aging effect is consistent with the applicant's disposition of Note A. For the third AMR item added, the applicant cited Note G and plant
| |
| -specific Note 1. Plant
| |
| -specific Note 1 states the following:
| |
| NUREG-1801 does not include air with borated water leakage for nickel
| |
| -alloy components. Similar to V.F
| |
| -13 for stainless steel, there are no aging effects for nickel alloy in air with borated water leakage. Additionally, the American Welding Society (AWS) "Welding Handbook," (Seventh Edition, Volume 4, 1982, Library of Congress) identifies that nickel chromium alloy materials that are alloyed with iron, molybdenum, tungsten, cobalt or copper in various combinations have improved corrosion resistance.
| |
| The staff reviewed the associated item and confirmed that the applicant's use of generic Note G for this item is appropriate in that the GALL Report, Revision 1, does not include entries for nickel-alloy components exposed to air with borated water leakage. The staff noted that the GALL Report, Revision 2, dated December 2010, includes entries for nickel
| |
| -alloy components exposed to air with borated water leakage. These entries indicate that no aging effect requiring management is present for this material
| |
| -environment combination. The staff also noted that these AMR items in the GALL Report, Revision 2, are based in part on EPRI Report 1000975, "Boric Acid Corrosion Guidebook, Revision 1." This report contains data (pages 4
| |
| -43) showing that "[t]here was no measurable corrosion of stainless steel piping surfaces or Inconel weld metal joining the stainless steel and carbon steel piping sections." The staff, therefore, finds the applicant's identification of aging effects for these components to be acceptable.
| |
| The staff also finds that the design modifications, and the applicant's commitment (Commitment 65) that the movable detectors will not be returned to service during the period of extended operation, eliminate the possibility of wear and RCS pressure boundary leakage through the prior movable detector dry path. Therefore, the staff's concerns described in RAIs 3.1.1-60-01, 3.1.1-60-02, and followup RAI 3.1.1 01/02 are resolved.
| |
| | |
| Aging Management Review Results 3-294 The staff noted that applicant's current and replacement incore detector assemblies are sufficiently different from the standard Westinghouse designed thimble tubes for movable detectors, in that:
| |
| * Failure of both the inner and outer flux thimble tubes inside of the reactor vessel, either due to wear or cracking, would not result in an RCS pressure boundary leakage.
| |
| * The applicant's isolation or capping and replacement program with the solid inner tubes has eliminated the possibility of RCS pressure boundary leakage through the prior movable detector dry path.
| |
| * Wear will not initiate in the inner tubes based on the placement of the applicant's commitment (Commitment 65).
| |
| * Periodic monitoring of the flux detectors would ensure that aging effects are detected prior to loss of intended function(s) as part of the applicant's technical specifications.
| |
| Therefore, the staff finds that the applicant has provided an acceptable basis that a Flux Thimble Tube Inspection Program is not needed to manage wear or cracking of the applicant's flux thimble tubes.
| |
| By letter dated July 2, 2013, the applicant submitted the third annual update to the LRA, identifying changes made to the CLB that materially affect the contents of the LRA. The applicant revised its response to RAIs 3.1.1.60
| |
| -01 and 3.1.1.60
| |
| -02, to state that the disconnected movable detector tube end is isolated by a normally closed valve or capped.
| |
| By letter dated October 2, 2014, the applicant submitted the fourth annual update to the LRA, identifying changes made to the CLB that materially affect the contents of the LRA. The applicant stated that, during the period covered by the fourth annual update, one incore detector assembly (tube and detector) was removed from service. The applicant stated that a replacement detector using a solid inner tube will be installed at this location during RFO 17.
| |
| By letter dated October 18, 2017, the applicant submitted the seventh annual update to the LRA identifying changes to the CLB that materially affect the contents of the LRA related to its flux thimble tubes. The applicant stated that it has completed the replacement of all of its original Westinghouse
| |
| -supplied incore detector assemblies with the new detectors using a solid inner tube. The applicant further stated that the completion of this design change also completes its license renewal Commitment 65.
| |
| LRA Table 3.1.1, item 3.1.1
| |
| -76 addresses, in part, ligament cracking due to corrosion of steel tube support plates exposed to secondary feedwater or steam. The applicant stated that such ligament cracking is not applicable because its tube support plates are made of stainless steel.
| |
| The staff reviewed the steam generator description in LRA Section 2.3.1.4 and UFSAR Section 5.4 in order to verify the design of the plant's steam generators and confirmed that the applicant's steam generators (Westinghouse Model F steam generators) have tube support plates made of stainless steel. Therefore, the staff finds that this item is not applicable.
| |
| LRA Table 3.1.1, item 3.1.1
| |
| -77 addresses the loss of material due to wastage and pitting corrosion in Ni
| |
| -alloy steam generator tubes and sleeves exposed to phosphate chemistry in Aging Management Review Results 3-295 secondary feedwater and steam. The applicant stated that this item is not applicable because it does not use phosphate chemistry.
| |
| The staff reviewed the description of the applicant's Water Chemistry Program in LRA Section B.2.1.28 in order to verify which water chemistry is used for the plant's steam generators and confirmed that the applicant's plant does not use a Phosphate Chemistry Program. Therefore, the staff finds that this item is not applicable.
| |
| LRA Table 3.1.1, item 3.1.1
| |
| -78 addresses the wall thinning due to flow
| |
| -accelerated corrosion in steel steam generator tube support lattice bars exposed to secondary feedwater and steam. The applicant stated that this item is not applicable because the Seabrook steam generators do not contain tube support lattice bars.
| |
| The staff reviewed the steam generator description in LRA Section 2.3.1.4 and UFSAR Section 5.4 in order to verify the design of the plant's steam generators and confirmed that the applicant's steam generators (Westinghouse Model F steam generators) do not contain tube support lattice bars. Therefore, the staff finds that this item is not applicable.
| |
| LRA Table 3.1.1, item 3.1.1
| |
| -79 addresses tube denting due to corrosion of steel tube support plates with Ni
| |
| -alloy steam generator tubes exposed to secondary feedwater and steam. The applicant stated that this item is not applicable because the steam generator tube support plates are made of stainless steel.
| |
| The staff reviewed the steam generator description in LRA Section 2.3.1.4 and UFSAR Section 5.4 to verify the design of the plant's steam generators. Based on this review, the staff confirmed that the applicant's plant steam generators (Westinghouse Model F steam generators) have tube support plates made of ferritic stainless steel with quatrefoil tube holes and a design resistant to corrosion, which is expected to preclude denting. Therefore, the staff finds that this item is not applicable.
| |
| LRA Table 3.1.1, item 3.1.1
| |
| -80 addresses the loss of fracture toughness due to thermal aging and neutron irradiation embrittlement of CASS RVI components. The applicant stated that these items are not applicable to Seabrook because the facility does not have CASS components in the RVIs.
| |
| The staff reviewed the reactor vessel internals description in LRA Section 2.3.1.3 and UFSAR Sections 4.5 and 5.2 in order to verify the component material of the plant's reactor vessel internals and confirmed that the applicant's reactor vessel internals do not have CASS components. Therefore, the staff finds that this item is not applicable.
| |
| LRA Table 3.1.1, item 3.1.1
| |
| -82 addresses cracking due to stress corrosion cracking in stainless steel steam generator primary side divider plate exposed to reactor coolant. The applicant stated that this item is not applicable because the Seabrook steam generators primary channel divider plate is not made of stainless steel.
| |
| The staff reviewed the steam generator description in LRA Section 2.3.1.4 and UFSAR Section 5.2 in order to verify the component material of the plant's steam generators and confirmed that the applicant's steam generators divider plate is not made of stainless steel but is made of SA
| |
| -533 steel. Therefore, the staff finds that this item is not applicable.
| |
| | |
| Aging Management Review Results 3-296 LRA Table 3.1.1, item 3.1.1
| |
| -87 addresses steel piping, piping components, and piping elements exposed to concrete and states that there are no aging effects, aging mechanisms, or AMPs. The GALL Report, Table IV, item IV.E
| |
| -6 (RP-01) recommends that there is no aging effect or aging mechanism and that no AMP is recommended for this component group exposed to this environment, and, therefore, the staff finds the applicant's determination acceptable.
| |
| The staff reviewed the LRA and the UFSAR and concludes that the applicant does not have any AMR results that are applicable for these items.
| |
| 3.1.2.1.2 Cracking Due to Stress
| |
| -Corrosion Cracking and Primary Water Stress
| |
| -Corrosion Cracking LRA Table 3.1.1, item 3.1.1
| |
| -69, addresses nickel
| |
| -alloy reactor vessel primary inlet and outlet nozzle welds exposed to reactor coolant, which are being managed for cracking. The LRA credits the ASME Code Section XI ISI Subsections IWB, IWC, and IWD Program, the Water Chemistry Program, and the Nickel
| |
| -Alloy Nozzles and Penetrations Program to manage the aging effect. The GALL Report recommends GALL Report AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and GALL Report AMP XI.M2, "Water Chemistry," to ensure that these aging effects are adequately managed. The associated AMR item cites generic Note A for the ASME Code Section XI ISI Subsections IWB, IWC, and IWD Program and Water Chemistry Program. The associated AMR item cites generic Note E for the Nickel-Alloy Nozzles and Penetrations Program.
| |
| For the item associated with generic Note E, GALL Report AMPs XI.M1 and XI.M2 recommend using visual inspections, volumetric inspections, and water chemistry maintenance within the EPRI water chemistry guidelines to manage the aging of these items. In its review of components associated with item 3.1.1
| |
| -69, for which the applicant cited generic Note E, the staff noted that the ASME Code Section XI ISI Subsections IWB, IWC, and IWD Program, the Water Chemistry Program, and the Nickel
| |
| -Alloy Nozzles and Penetrations Program all propose to manage the aging of nickel
| |
| -alloy reactor vessel primary inlet and outlet nozzle welds through the use of visual inspections, volumetric inspections, and repair and replacement activities, along with maintaining the water chemistry within the EPRI water chemistry guidelines.
| |
| The staff's evaluation of the applicant's ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program, Water Chemistry Program, and Nickel
| |
| -Alloy Nozzles and Penetrations Program are documented in SER Sections 3.0.3.1.1, 3.0.3.1.2, and 3.0.3.3.4, respectively. In its review of components associated with item 3.1.1
| |
| -69, the staff finds the applicant's proposal to manage aging using the ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program, Water Chemistry Program, and Nickel
| |
| -Alloy Nozzles and Penetrations Program acceptable for the following reasons:
| |
| * The Water Chemistry Program establishes the plant water chemistry control parameters and their limits to mitigate the environmental effect on the aging and identifies the actions required if the parameters exceed the limits.
| |
| * The ASME Code Section XI ISI Subsection IWB, IWC, and IWD Program uses volumetric or visual inspection, which is adequate to detect and manage the aging effect consistent with the guidance in the GALL Report.
| |
| | |
| Aging Management Review Results 3-297
| |
| * The Nickel
| |
| -Alloy Nozzles and Penetrations Program complies with the applicable NRC Orders and implements applicable NRC bulletins, generic letters, and staff
| |
| -accepted industry guidelines.
| |
| * The use of these three programs is sufficient to manage the aging effects of the nickel
| |
| -alloy reactor vessel primary inlet and outlet nozzle welds.
| |
| The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintai ned consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.1.2.1.3 Conclusion for Aging Management Reviews Consistent with the GALL Report The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing the associated aging effects. On the basis of its review, the staff concludes that the AMR results that the applicant claimed to be consistent with the GALL Report are consistent with the GALL Report AMRs. Therefore, the staff concludes that the applicant demonstrated that the aging effects for these components will be adequately managed so that their intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.1.2.2 Aging Management Review Results That Are Consistent with the GALL Report for Which Further Evaluation is Recommende d LRA Section 3.1.2.2 provides further evaluation of aging management, as recommended by the GALL Report for the RCS components. The applicant provided information concerning how it will manage the following aging effects:
| |
| * cumulative fatigue damage
| |
| * loss of material due to general, pitting, and crevice corrosion
| |
| * loss of fracture toughness due to neutron irradiation embrittlement
| |
| * cracking due to SCC and IGSCC
| |
| * crack growth due to cyclic loading
| |
| * loss of fracture toughness due to neutron irradiation embrittlement and void swelling
| |
| * cracking due to SCC
| |
| * cracking due to cyclic loading
| |
| * loss of preload due to stress relaxation
| |
| * loss of material due to erosion
| |
| * cracking due to flow
| |
| -induced vibration
| |
| * cracking due to SCC and irradiation
| |
| -assisted stress corrosion cracking (IASCC)
| |
| * cracking due to PWSCC
| |
| * wall thinning due to flow
| |
| -accelerated corrosion
| |
| * changes in dimensions due to void swelling
| |
| * cracking due to SCC and PWSCC
| |
| * cracking due to SCC, PWSCC, and IASCC Aging Management Review Results 3-2 98 For component groups evaluated in the GALL Report, for which the applicant claimed consistency with the GALL Report and for which the report recommends further evaluation, the staff audited and reviewed the applicant's evaluation. The staff determined whether the applicant adequately addressed the issues for which further evaluation is recommended. The staff reviewed the applicant's further evaluations against the criteria contained in SRP
| |
| -LR Section 3.1.2.2. The staff's review of the applicant's further evaluation follows.
| |
| 3.1.2.2.1 Cumulative Fatigue Damage LRA Section 3.1.2.2.1 describes the applicant's AMR for managing cumulative fatigue damage in ASME Code Class 1 components and other non
| |
| -Class 1 components that were analyzed to ASME Code Section III, Classes 1, fatigue evaluations. The applicant stated that fatigue is a TLAA as defined in 10 CFR 54.3, and these TLAAs are evaluated in accordance with 10 CFR 54.21(c)(1). Further evaluation of these TLAAs is discussed separately in LRA Section 4.3.
| |
| The applicant identified that the following AMRs in LRA Table 3.1.1 are applicable and stated the following for each applicable item:
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| * Item 3.1.1 The applicant stated that the TLAAs for stainless steel and nickel
| |
| -alloy RVIs components were evaluated in accordance with 10 CFR 54.21(c).
| |
| * Item 3.1.1 The applicant stated that the TLAAs for nickel
| |
| -alloy tubes and sleeves in a reactor coolant and secondary feedwater and steam environment were evaluated in accordance with 10 CFR 54.21(c).
| |
| * Item 3.1.1 The applicant stated that steel and stainless steel RCPB closure bolting, head closure studs, support skirts and attachment welds, pressurizer relief tank components, steam generator components, piping, and components external surfaces and bolting were evaluated in accordance with 10 CFR 54.21(c).
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| * Item 3.1.1 The applicant stated that steel; stainless steel; and nickel
| |
| -alloy RCPB piping, piping components, piping elements; flanges; nozzles and safe ends; pressurizer vessel shell heads and welds; heater sheaths and sleeves; penetrations; and thermal sleeves were evaluated in accordance with 10 CFR 54.21(c).
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| * Item 3.1.1 The applicant stated that steel; stainless steel; steel with nickel alloy or stainless steel cladding; nickel
| |
| -alloy reactor vessel components such as flanges; nozzles; penetrations; pressure housings; safe ends; thermal sleeves; and vessel shells, heads and welds were evaluated in accordance with 10 CFR 54.21(c).
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| * Item 3.1.1 The applicant stated that steel; stainless steel; steel with nickel alloy or stainless steel cladding; nicke l-alloy steam generator components such as flanges; penetrations; nozzles; safe ends, and vessel lower heads and welds were evaluated in accordance with 10 CFR 54.21(c).
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| The staff reviewed LRA Section 3.1.2.2.1 against the further evaluation criteria in S RP-LR Section 3.1.2.2.1, which states that fatigue is a TLAA, as defined in 10 CFR 54.3, and these TLAAs are to be evaluated in accordance with the TLAA acceptance criteria requirements in 10 CFR 54.21(c) and in accordance with SRP
| |
| -LR Section 4.3, "Metal Fatigue Analysis." The staff reviewed the applicant's AMR items and finds that the AMR results are consistent with the recommendations of the GALL Report and SRP
| |
| -LR except for the area identified below.
| |
| | |
| Aging Management Review Results 3-299 In its review of the components associated with item 3.1.1-8, the staff noted that LRA Tables 3.2.2-3, 3.2.2-4, and 3.3.2
| |
| -3 included several AMR items that referenced item 3.1.1
| |
| -8. The staff noted that LRA Section 4.3.7 indicated that these systems were designed in accordance with ASME Code Section III Class 2 and Class 3 requirements. By letter dated January 21, 2010, the staff issued RAI 3.3.2.2.1
| |
| -2, asking the applicant to clarify which portions of these systems are represented by item 3.1.1
| |
| -8 in LRA Tables 3.2.2
| |
| -3, 3.3.2-4, and 3.3.2
| |
| -3. The staff's review of the applicant's response to RAI 3.3.2.2.1
| |
| -2 is documented in SER Sections 3.2.2.2.1 and 3.3.2.2.1.
| |
| Based on the staff's review, the staff concludes that the applicant met the SRP
| |
| -LR Section 3.1.2.2.1 criteria. For those items that apply to LRA Section 3.1.2.2.1, the staff determined that the LRA is consistent with the GALL Report and that the applicant demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). SER Section 4.3 documents the staff's review of the applicant's evaluation of the TLAAs for these components.
| |
| 3.1.2.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosio n The staff reviewed LRA Section 3.1.2.2.2 against the criteria in SRP
| |
| -LR Section 3.1.2.2.2. LRA Section 3.1.2.2.2 addresses loss of material due to general, pitting, and crevice corrosion for certain portions (for PWRs) of the steam generators. The staff's review noted four items:
| |
| (1) Table 3.1.1, item 3.1.1
| |
| -12, is only applicable to Babcock & Wilcox Co. OTSGs. Therefore, it is not applicable to Seabrook.
| |
| (2) Table 3.1.1, item 3.1.1
| |
| -13, is applicable to BWRs only, as discussed in SER Section 3.1.2.1.1 above.
| |
| (3) Table 3.1.1, items 3.1.1
| |
| -14 and 3.1.1
| |
| -15, are applicable to BWRs only, as discussed in SER Section 3.1.2.1.1 above.
| |
| (4) LRA Section 3.1.2.2.2.4 is associated with LRA Table 3.1.1, item 3.1.1
| |
| -16, and addresses steel steam generator components (feedwater and main steam nozzles, lower shell, secondary handholes, secondary manways, shell penetrations, top head, transition cone, and upper shell) exposed to secondary feedwater and steam, which are being managed for loss of material due to general, pitting, and crevice corrosion by the Water Chemistry Program and the ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program.
| |
| The criteria in SRP
| |
| -LR Section 3.1.2.2.2, item 4, states that loss of material due to general, pitting and crevice corrosion could occur for steel PWR steam generator upper and lower shell and transition cone exposed to secondary feedwater and steam. The SRP-LR also states that the existing program relies on control of chemistry to mitigate corrosion and ISI to detect loss of material. The SRP
| |
| -LR further states that, in accordance with NRC IN 90
| |
| -04, "Cracking of the Upper Shell
| |
| -to-Transition Cone Girth Welds in Steam Generators," the program may not be sufficient to detect pitting and crevice corrosion if general and pitting corrosion of the shell is known to exist, and augmented inspections may be needed to manage the aging effect. The SRP
| |
| -LR clarifies that this special concern about capability of standard ASME Code Section XI inspections to detect pitting and crevice corrosion is limited to Westinghouse Model 44 Aging Management Review Results 3-300 and 51 steam generators, where a high stress region exists at the shell to transition cone weld. The staff also noted that the discussion in LRA Table 3.1.1, item 3.1.1
| |
| -16, states that the steam generators are Westinghouse Model F and that additional inspection procedures (beyond those specified in ASME Code Section XI) are not required. The staff confirmed that the applicant's UFSAR Section 5.4.2.2 states that the steam generators are Model F and the NRC IN 90
| |
| -04 recommendation regarding augmented inspections is limited to only Westinghouse steam generator Models 44 and 51. Because the applicant's steam generators are not Westinghouse Model 44 or 51, the staff finds acceptable the applicant's determination that augmented inspections are not needed.
| |
| The staff noted that, in the GALL Report, AMR item IV.D1
| |
| -12(R-34) is the only component related to SRP-LR Table 3.1.1, item 3.1.1
| |
| -16. Specifically, AMR item IV.D1
| |
| -12(R-34) is the steel steam generator upper and lower shell and transition cone exposed to secondary feedwater and steam. However, the applicant extended the AMR results for this item to include other secondary steam generator components made of the same material and exposed to the same environment. The staff also noted that ASME Code Section XI, Examination Category C
| |
| -A, item C1.10, is applicable for the steam generator upper and lower shell and transition cone and requires volumetric examination of shell circumferential welds at locations of gross structural discontinuity, specifically at the cylindrical shell to conical shell junctions. It was not clear to the staff if the applicant proposed this solely to rely on the code
| |
| -required volumetric inspection, item C1.10, or whether it also intended to use visual examinations to confirm effectiveness of secondary water chemistry to mitigate loss of material due to general, pitting, and crevice corrosion for these components. By letter dated January 5, 2011, the staff issued RAI 3.1.2.2.2.4
| |
| -01, asking the applicant to describe the examinations that will be used for this AMR item.
| |
| In its response dated February 3, 2011, the applicant stated that the Steam Generator Tube Integrity Program includes visual inspections for degradation of secondary handholds, secondary manways, shell penetrations, steam generator shell internal surface, transition cone internal surface, top head, and shell weld internal surfaces. The applicant further stated that the design of the steam generators prevents internal access to the feedwater and main steam nozzles for visual inspection and that, for these components, only volumetric examinations will be performed.
| |
| The applicant revised LRA Table 3.1.1, item 3.1.1
| |
| -16, to state that both the ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program and the Steam Generator Tube Integrity Program will be used to verify the effectiveness of the Water Chemistry Program to manage loss of material due to general, pitting, and crevice corrosion in the steel components of the steam generators exposed to secondary feedwater or steam. In LRA Table 3.1.2
| |
| -4, the applicant revised many AMR lines for steel components that refer to LRA Table 3.1.1, item 3.1.1-16. For three AMR lines applicable to the steel steam generator lower shell, transition cone, and upper shell, respectively, the AMP was revised to credit the Steam Generator Tube Integrity Program in addition to the ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program and the Water Chemistry Program for management of loss of material. For four AMR lines applicable to the steel steam generator secondary handholes, secondary manways, shell penetrations, and top head, respectively, the AMP was revised to credit the Steam Generator Tube Integrity Program and the Water Chemistry Aging Management Review Results 3-301 Program for management of loss of material. The staff noted that, for components where ASME Code Section XI specifies ISIs, the applicant is crediting the required ASME Code Section XI volumetric inspections and is supplementing those inspections with additional Steam Generator Tube Integrity Program visual inspections. Additionally, for components where ASME Code Section XI does not specify inspections, the applicant is crediting Steam Generator Tube Integrity Program visual inspections for verification of Water Chemistry Program effectiveness.
| |
| The staff's evaluations of the applicant's ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program, Water Chemistry Program, and Steam Generator Tube Integrity Program are documented in SER Sections 3.0.3.1.1, 3.0.3.1.2, and 3.0.3.2.2, respectively. The staff noted that the applicant's Water Chemistry Program follows EPRI secondary water chemistry guidelines, which is consistent with recommendations in the GALL Report, and provides monitoring and control of secondary water chemistry to mitigate the potential for general, pitting, and crevice corrosion of steel secondary
| |
| -side steam generator components. The staff also noted that the applicant's ASME Code Section XI ISI, Subsections IWB, IWC and IWD Program is consistent with recommendations in the GALL Report and provides the Code
| |
| -required volumetric inspections and visual inspections of the steel secondary
| |
| -side steam generator components. In addition, the staff noted that the applicant's Steam Generator Tube Integrity Program is based on NEI 97
| |
| -02, Revision 2, "Steam Generator Program Guidelines," which is consistent with staff recommendations documented in the GALL Report. This program includes visual inspections that are capable of detecting loss of material due to general, pitting and crevice corrosion in steel secondary
| |
| -side steam generator components.
| |
| The staff finds that the applicant met the further evaluation criteria, and the applicant's proposal to manage aging using the Water Chemistry Program, the ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program, and the Steam Generator Tube Integrity Program is acceptable for the following reasons:
| |
| * The Water Chemistry Program provides mitigation of the aging effect for steel secondary-side steam generator exposed to feedwater and steam.
| |
| * The ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program and the Steam Generator Tube Integrity Program provide examination of the components to confirm effectiveness of the Water Chemistry Program to mitigate the aging effects.
| |
| * The combination of programs proposed by the applicant is consistent with the recommendations in the GALL Report for aging management of these components.
| |
| Based on the programs identified, the staff concludes that the applicant's programs meet SRP
| |
| -LR Section 3.1.2.2.2, item 4, criteria. For those items that apply to LRA Section 3.1.2.2.2.4, the staff determined that the LRA is consistent with the GALL Report and that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.1.2.2.3 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement (1) LRA Section 3.1.2.2.3 is associated with LRA Table 3.1.1, item 3.1.1
| |
| -17, and states that TLAAs are evaluated in accordance with 10 CFR 54.21(c)(1) and that the evaluation of Aging Management Review Results 3-302 this TLAA is addressed in Section 4.2. This is consistent with SRP
| |
| -LR Section 3.1.2.2.3, item 1, and is, therefore, acceptable.
| |
| (2) LRA Section 3.1.2.2.3 is associated with LRA Table 3.1.1, item 3.1.1
| |
| -18, and addresses steel (with or without stainless steel cladding) reactor vessel beltline shell, nozzles, and welds exposed to reactor coolant and neutron flux, which are being managed for loss of fracture toughness due to neutron irradiation embrittlement by Seabrook AMP B.2.1.19, "Reactor Vessel Surveillance." The criteria in SRP
| |
| -LR Section 3.1.2.2.3, item 2, states that loss of fracture toughness due to neutron irradiation embrittlement could occur for steel (with or without stainless steel cladding) reactor vessel beltline shell, nozzles, and welds exposed to reactor coolant and neutron flux. The SRP
| |
| -LR also states that the applicant should submit its proposed withdrawal schedule for approval prior to implementation. Untested capsules placed in storage must be maintained for future insertion. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that the required information is included in the applicant's Reactor Vessel Surveillance Program.
| |
| The staff's evaluation of the applicant's Reactor Vessel Surveillance Program (LRA Section B.2.1.19) is documented in SER Section 3.0.3.2.11. The staff noted that the applicant did submit a Surveillance Program in 1983, and the LRA does include a commitment to follow the requirements of 10 CFR Part 50, Appendix H, and ASTM E185-82 protocol for the capsule withdrawal schedule (Commitment 20). In addition, the staff noted that Section B.2.1.19 includes a commitment (Commitment 21) to maintain untested capsules in storage for future insertion, if needed. The staff also noted that Table 3.1.1, item 3.1.1
| |
| -18, is aligned with the applicant's commitments, as described in LRA Section B.2.1.19 Based on the acceptance of the Reactor Vessel Surveillance Program discussed in Section 3.0.3.2.11 and the commitments listed in LRA Appendix A, Section A.3, the staff concludes that the applicant's programs meet SRP
| |
| -LR Section 3.1.2.2.3, item 2, criteria. For those items that apply to LRA Section 3.1.2.2.3.2, the staff concludes that the LRA is consistent with the GALL Report and that the applicant demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.1.2.2.4 Cracking Due to Stress
| |
| -Corrosion Cracking and Intergranular Stress
| |
| -Corrosion Cracking Table 3.1.1, items 3.1.1
| |
| -19 and 3.1.1-20 are not applicable to Seabrook, as they are applicable to BWRs only. See SER Section 3.1.2.1.1 above.
| |
| 3.1.2.2.5 Crack Growth Due to Cyclic Loading LRA Section 3.1.2.2.5 states that item 3.1.1
| |
| -21 is not applicable because the stainless steel cladding is not fabricated with a high
| |
| -heat-input welding process. SRP
| |
| -LR Section 3.1.2.2.5 states that cyclic crack growth could occur if the cladding was welded to the RPV SA
| |
| -508, Class 2 forgings using a high
| |
| -heat-input welding process. After review, the staff concluded that item 3.1.1-21, crack growth due to cyclic loading, is not applicable because the cladding procedure Aging Management Review Results 3-303 used for the applicant's RV was qualified to ensure underclad cracking and the subsequent crack growth due to cyclic loading would not occur. The staff noted that the applicant used a special procedure qualification for its welding of the cladding to those RV components that were fabricated from SA
| |
| -508, Class 2 low alloy steel forgings. The staff also noted that the procedure qualification included a special evaluation to assure freedom from underclad cracking in these cladding
| |
| -to-forging welds. Specifically, the staff verified that UFSAR Sections 5.2.3 and 5.3.1.4 indicate that the applicant applied the NRC's recommended weld control process in Regulatory Guide (RG) 1.43, "Control of Stainless Steel Weld Cladding of Low Alloy Steel Components," as the process for controlling the welding fabrication of the cladding to those RV components that were fabricated from SA 508, Class 2 forging materials. The staff also verified that UFSAR Section 1.8 identifies that the applicant's procedural qualification was performed both in accordance with the weld fabrication requirements in Sections III and XI of the ASME Code and in accordance with supplemental qualification criteria (i.e., Position C.2) of RG 1.43, which provides the staff's recommended welding qualification process controls for avoiding underclad cracking in these cladding
| |
| -to-forging welds. The staff determined that the RPV underclad cracking and the subsequent crack growth due to cyclic loading would not occur and, therefore, item 3.1.1
| |
| -21 is not applicable. The staff evaluation of the absence of a TLAA for reactor vessel underclad cracking is documented in SER Section 4.7.1.2.
| |
| 3.1.2.2.6 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement and Void Swelling The staff reviewed LRA Section 3.1.2.2.6 and Table 3.1.1, Item 3.1.1
| |
| -22, against the criteria in SRP-LR 3.1.2.2.6, which recommends no further AMR if the applicant provides a commitment in the UFSAR supplement to do the following:
| |
| * participate in the industry programs for investigating and managing aging effects on reactor internals
| |
| * evaluate and implement the results of the industry programs as applicable to the reactor internals
| |
| * upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval The staff noted that the applicant's commitment (Commitment
| |
| : 1) in LRA Appendix A, Section A3, is consistent with the commitment described in SRP
| |
| -LR 3.1.2.2.6.
| |
| The staff also noted that all of the AMR results lines that refer to Table 3.1.1, Item 3.1.1
| |
| -22, align with the applicant's commitment as described in LRA Appendix A, Section A3. The staff finds the applicant's proposal acceptable because the discussion of the AMR item refers to the applicant's AMP (PWR Vessel Internals Program), which includes the appropriate commitment in the UFSAR supplement.
| |
| Based on the staff's evaluation, the staff concludes that the applicant's program meets the SRP
| |
| -LR Section 3.1.2.2.6 criteria. For those AMR items that apply to LRA Section 3.1.2.2.6, the staff concludes that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| | |
| Aging Management Review Results 3-304 3.1.2.2.7 Cracking Due to Stress
| |
| -Corrosion Cracking (1) LRA Section 3.1.2.2.7.1 is associated with LRA Table 3.1.1, item 3.1.1
| |
| -23, and addresses stainless steel reactor vessel flange leak detection lines exposed to reactor coolant, which are being managed for cracking due to SCC by the ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program. SRP
| |
| -LR Section 3.1.2.2.7, item 1, states that cracking due to SCC could occur for stainless steel exposed to reactor coolant. The SRP
| |
| -LR also states that a plant
| |
| -specific AMP should be evaluated to ensure that this aging effect is adequately managed. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that Seabrook will implement VT
| |
| -2 examinations to identify and evaluate the degradation of stainless steel reactor vessel flange leak detection lines to ensure that there is no loss of intended function.
| |
| The staff's evaluation of the applicant's ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program, is documented in SER Section 3.0.3.1.1. The staff noted that SCC will start at the surface and could be found with visual inspections as long as the critical flaw size is relatively large. The staff also noted that the stainless steel used for these components is extremely tough, such that the critical flaw size is normally large and easy to find with VT
| |
| -2 inspections. In its review of components associated with item 3.1.1-23, the staff finds that the applicant met the further evaluation criteria; the applicant's proposal to manage aging using the ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program, is acceptable because the proposed VT
| |
| -2 inspections should find any cracking due to SCC.
| |
| Based on the program identified, the staff concludes that the applicant's program meets SRP-LR Section 3.1.2.2.7, item 1, criteria. For those items that apply to LRA Section 3.1.2.2.7.1, the staff determined that the LRA is consistent with the GALL Report. The staff also finds that the applicant demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| (2) LRA Section 3.1.2.2.7.2 is associated with LRA Table 3.1.1, item 3.1.1
| |
| -24, and addresses Class 1 PWR CASS piping, piping components, and piping elements exposed to reactor coolant, which are being managed for cracking due to SCC by the Water Chemistry Program and the ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program. The criteria in SRP
| |
| -LR Section 3.1.2.2.7 item 2, states that the cracking due to SCC could occur for Class 1 PWR CASS piping, piping components, and piping elements exposed to reactor coolant. SRP
| |
| -LR Section 3.1.2.2.7 also states that the existing program relies on the control of water chemistry to mitigate SCC that could occur for CASS components that do not meet the NUREG
| |
| -0313 guidelines with regard to ferrite and carbon contents. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that the ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program, will be used to verify the effectiveness of the Water Chemistry Program. In its review of components associated with LRA Table 3.1.1, item 3.1.1
| |
| -24, the staff noted that the applicant related the AMR items to GALL Report, item IV.C2
| |
| -3. The staff also noted that, for the CASS components that do not meet NUREG
| |
| -0313 guidelines on material susceptibility, GALL AMR item IV.C2
| |
| -3 recommends a plant
| |
| -specific program to Aging Management Review Results 3-305 include adequate inspection methods and a flaw evaluation methodology for the CASS components that are susceptible to thermal aging embrittlement. LRA Section 3.1.2.2.7.2 states that the ASME Code Section XI ISI, Subsections IWB, IWC and IWD Program rely on VT
| |
| -2 examinations to identify and evaluate cracking of the CASS components. The staff noted that a VT
| |
| -2 examination is used to detect leakage from pressure-retaining components, whereas a volumetric examination can detect a crack before there is leakage. The staff also noted that a surface examination or VT
| |
| -1 examination can provide better resolution for detecting cracking than a VT
| |
| -2 examination.
| |
| By letter dated January 5, 2011, the staff issued RAI 3.1.2.1
| |
| -1, requesting that the applicant clarify whether a VT
| |
| -2 examination is the only method used to detect this aging effect in CASS Class 1 piping, piping elements, and components. The staff also requested that, if another examination method such as volumetric, surface or VT
| |
| -1 examination is used, the applicant should clarify what the examination method is and justify why the aging management method is adequate to detect and manage the aging effect. The staff further requested that, if the VT
| |
| -2 examination is the only examination method used, the applicant should justify why a VT
| |
| -2 examination without volumetric, surface, and VT
| |
| -1 examinations is adequate to detect and manage cracking.
| |
| In its response dated February 3, 2011, the applicant stated that, as shown in LRA Table 3.1.1
| |
| -23, the ASME Code Section XI ISI, Subsections IWB, IWC and IWD Program, is credited to manage SCC of the Class 1 CASS piping, piping components, and piping elements. The applicant also stated that the VT
| |
| -2 examination method was inadvertently identified as the only inspection method and that the ASME Code Section XI ISI, Subsections IWB, IWC and IWD Program is implemented in accordance with the requirements of 10 CFR 50.55a, with specified limitations, modifications, NRC approved alternatives, and applicable provisions of ASME Code Section XI. The applicant further indicated that it is revising LRA Section 3.1.2.2.7.2 accordingly to clarify that VT
| |
| -2 examination is not the only examination credited to manage this aging effect. In addition, the applicant indicated that, during the period of extended operation, should the ISI Program require that volumetric examinations be performed per ASME Code Section XI, Table IWB
| |
| -2500-1, Examination Category B
| |
| -J, on the Class 1 pipe welds, then an ultrasonic examination method, qualified under ASME Code Section XI, Appendix VIII, will be used or an NRC
| |
| -approved alternative (such as enhanced visual examination) will be implemented.
| |
| Based on its review, the staff finds the applicant's response to RAI 3.1.2.1
| |
| -1 acceptable because the applicant clarified the following:
| |
| * The ASME Code Section XI ISI, Subsections IWB, IWC and IWD Program is implemented in accordance with the requirements of 10 CFR 50.55a, which is adequate to detect SCC of the components.
| |
| * A VT-2 examination is not the only inspection method used to manage this aging effect.
| |
| * If volumetric examinations are required per the ASME Code, an ultrasonic examination method qualified under ASME Code Section XI, Appendix VIII, will Aging Management Review Results 3-306 be used or an NRC
| |
| -approved alternative (such as enhanced visual examination) will be implemented, which is adequate to detect cracking due to SCC of the components.
| |
| The staff's concerns described in RAI 3.1.2.1
| |
| -1 are resolved.
| |
| The staff's evaluations of the applicant's Water Chemistry Program and ASME Code Section XI ISI, Subsections IWB, IWC and IWD Program, are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.1, respectively. The applicant stated that the Water Chemistry Program controls water chemistry parameters by periodic monitoring and control of detrimental contaminants below the established limits that are known to cause material degradation. This program is based on EPRI guidelines, and periodic sampling is performed and analyzed for levels of chlorides, fluorides, sulfates, lithium, and dissolved oxygen and hydrogen so that cracking due to SCC in the CASS components is mitigated. The applicant further stated that the ASME Code Section XI ISI, Subsections IWB, IWC and IWD Program includes visual, surface, and volumetric inspections to detect and manage cracking due to SCC. The applicant stated that indications or relevant conditions are evaluated in accordance with IWB
| |
| -3000 for Class 1 components. On the basis of its review, the staff finds that the applicant met the further evaluation criteria. Additionally, the applicant's proposal to manage aging using the Water Chemistry Program and ASME Code Section XI ISI, Subsections IWB, IWC and IWD Program is acceptable because the Water Chemistry Program monitors and controls water chemistry to mitigate cracking due to SCC, and the ASME Code Section XI ISI, Subsections IWB, IWC and IWD Program will perform inspections using visual, surface, and volumetric examinations in accordance with the requirements of the ASME Code Section XI, as modified and limited in 10 CFR 50.55a, which is adequate to verify the effectiveness of the Water Chemistry Program and manage cracking due to SCC.
| |
| Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.7 criteria. For those items that apply to LRA Section 3.1.2.2.7.2, the staff determined that the LRA is consistent with the GALL Report. The staff also finds that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.1.2.2.8 Cracking Due to Cyclic Loading Table 3.1.1, items 3.1.1
| |
| -25 and 3.1.1
| |
| -26, are applicable to BWRs only, as discussed in SER Section 3.1.2.1.1 above.
| |
| 3.1.2.2.9 Loss of Preload Due to Stress Relaxation The staff reviewed LRA Section 3.1.2.2.9 against the criteria in SRP
| |
| -LR Section 3.1.2.2.9. LRA Section 3.1.2.2.9 addresses loss of preload due to stress relaxation that could occur in stainless steel and Ni-alloy PWR RVIs screws, bolts, and hold
| |
| -down springs exposed to reactor coolant as an aging effect that the applicant will manage, consistent with the SRP
| |
| -LR, by the ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program. This AMP is enhanced with Commitment 1, which is also identified in the UFSAR supplement description of the program.
| |
| | |
| Aging Management Review Results 3-307 The staff reviewed LRA Section 3.1.2.2.9 and Table 3.1.1, item 3.1.1
| |
| -27, against criteria in SRP-LR 3.1.2.2.9. LRA Section 3.1.2.2.9 addresses loss of preload due to stress relaxation that could occur in stainless steel and Ni
| |
| -alloy PWR RVIs screws, bolts, and hold
| |
| -down springs exposed to reactor coolant. The SRP
| |
| -LR recommends no further AMR if the applicant provides a commitment in the UFSAR supplement to do the following:
| |
| * participate in the industry programs for investigating and managing aging effects on reactor internals
| |
| * evaluate and implement the results of the industry programs as applicable to the reactor internals
| |
| * upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval The staff noted that the applicant's commitment (Commitment 1) in LRA Appendix A, Section A3, is consistent with the commitment described in SRP
| |
| -LR 3.1.2.2.9.
| |
| The staff also noted that all of the AMR results lines that refer to Table 3.1.1, item 3.1.1
| |
| -27, align with the applicant's commitment as described in LRA Appendix A, Section A3. The staff finds the applicant's proposal acceptable because the discussion of the AMR item refers to the applicant's AMP (PWR Vessel Internals Program), which includes the appropriate commitment in the UFSAR supplement.
| |
| Based on the staff's evaluation, the staff concludes that the applicant's program meets the SRP
| |
| -LR Section 3.1.2.2.9 criteria. For those AMR items that apply to LRA Section 3.1.2.2.9, the staff concludes that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.1.2.2.10 Loss of Material Due to Erosion LRA Section 3.1.2.2.10, associated with LRA Table 3.1.1, item 3.1.1
| |
| -28, addresses loss of material due to erosion in steel steam generator impingement plates and supports exposed to secondary feedwater. The applicant stated that this item is not applicable because steel steam generator feedwater impingement plates and supports do not exist in its steam generators. The staff reviewed UFSAR Section 5.4.2 and confirmed that the design of the applicant's steam generators do not contain steel steam generator feedwater impingement plates and supports; therefore, it finds the applicant's claim acceptable.
| |
| 3.1.2.2.11 Cracking Due to Flow
| |
| -Induced Vibration Table 3.1.1, item 3.1.1
| |
| -29, is applicable to BWRs only, as discussed in SER Section 3.1.2.1.1 above. 3.1.2.2.12 Cracking Due to Stress
| |
| -Corrosion Cracking and Irradiation
| |
| -Assisted Stress
| |
| -Corrosion Cracking The staff reviewed LRA Section 3.1.2.2.12 and Table 3.1.1, item 3.1.1
| |
| -30, against criteria in SRP-LR 3.1.2.2.12. LRA Section 3.1.2.2.12 addresses cracking due to SCC and IASCC that Aging Management Review Results 3-308 may occur in stainless steel PWR reactor internals exposed to reactor coolant. This LRA section states that the existing program relies on control of water chemistry to mitigate cracking due to SCC and IASCC. SRP
| |
| -LR 3.1.2.2.12 recommends no further AMR if the applicant provides a commitment in the UFSAR supplement to do the following:
| |
| * participate in the industry programs for investigating and managing aging effects on reactor internals
| |
| * evaluate and implement the results of the industry programs as applicable to the reactor internals
| |
| * upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval The staff noted that the applicant's commitment (Commitment 1) in LRA Appendix A, Section A3, is consistent with the commitment described in SRP
| |
| -LR 3.1.2.2.12.
| |
| The staff also noted that all of the AMR results lines that refer to Table 3.1.1, item 3.1.1
| |
| -30, align with the applicant's commitment, as described in LRA Appendix A, Section A3. The staff finds the applicant's proposal acceptable because the discussion of the AMR item refers to the applicant's AMP (PWR Vessel Internals Program), which includes the appropriate commitment in the UFSAR supplement.
| |
| In LRA Section 3.1.2.2.12, the applicant stated that, for managing the aging of cracking due to SCC and IASCC of stainless steel reactor internals components exposed to reactor coolant, the facility's Water Chemistry Program is augmented by the commitment described above. When augmented by the commitment above, the staff finds the facility's Water Chemistry Program acceptable for managing SCC and IASCC of stainless steel reactor internals components exposed to reactor coolant because the Water Chemistry Program will control contaminants that can contribute to SCC of stainless steel.
| |
| The staff's evaluation of the applicant's Water Chemistry Program is documented in SER Section 3.0.3.1.2. In its review of components associated with item 3.1.1
| |
| -30, the staff finds the applicant's proposal to manage aging using the Water Chemistry Program acceptable because use of the Water Chemistry Program to manage cracking is consistent with GALL when combined with the commitment described above.
| |
| Based on the programs identified, the staff concludes that the applicant's program meets SRP
| |
| -LR Section 3.1.2.2.12 criteria. For those items that apply to LRA Section 3.1.2.2.12, the staff determined that the LRA is consistent with the GALL Report. The staff also finds that the applicant 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 LRA Section 3.1.2.2.13 and LRA Table 3.1.1, item 3.1.1
| |
| -31, address PWR components made of nickel alloy and steel with nickel
| |
| -alloy cladding, including RCPB components and penetrations inside the RCS, such as pressurizer heater sheaths and sleeves, nozzles, and other internal components, with the exception of reactor vessel upper head nozzles and penetrations exposed Aging Management Review Results 3-309 to reactor coolant. These components are being managed for cracking due to PWSCC by the ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program, the Nickel
| |
| -Alloy Nozzles and Penetrations Program, and the Water Chemistry Program. SRP
| |
| -LR Section 3.1.2.2.13 states that cracking due to PWSCC could occur for PWR components made of nickel alloy and steel with nickel
| |
| -alloy cladding exposed to reactor coolant. The SRP
| |
| -LR also states that, with the exception of reactor vessel upper head nozzles and penetrations, the GALL Report recommends ASME Code Section XI ISI (for Class 1 components) and control of water chemistry. For nickel
| |
| -alloy components, no further AMR is necessary if the applicant complies with applicable NRC Orders and provides a commitment in the UFSAR supplement to implement applicable bulletins, generic letters, and staff
| |
| -accepted industry guidelines. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that it will implement those programs mentioned above to manage the aging effects of cracking due to PWSCC in nickel-alloy components in the RCS, in the nickel
| |
| -alloy bottom instrument tube and core support pads/core guide lugs in the reactor vessel, and the nickel
| |
| -alloy steam generator primary nozzle weld in the steam generator.
| |
| The staff's evaluations of the applicant's three AMPs, ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program, Water Chemistry Program, and Nickel
| |
| -Alloy Nozzles and Penetrations Program, are documented in SER sections 3.0.3.1.1, 3.0.3.3.4, and 3.0.3.1.2, respectively. In its review of these AMPs, the staff found them to be acceptable for managing aging. Additionally, the staff noted that the Nickel
| |
| -Alloy Nozzles and Penetrations Program states that the applicant will comply with applicable NRC Orders. Additionally, Commitment 59, which is associated with the Nickel
| |
| -Alloy Nozzles and Penetration Program (submitted by letter dated January 13, 2011, and contained in LRA Section A.2.2.3), commits to implementing bulletins, generic letters, and staff
| |
| -accepted industry guidelines.
| |
| In its review of components associated with Table 3.1.1, item 3.1.1
| |
| -31, the staff finds the applicant's proposal to manage aging using the ASME Code Section XI ISI Program, the Water Chemistry Program, and the Nickel
| |
| -Alloy Nozzles and Penetrations Program, acceptable. The components under consideration are consistent with those in the GALL Report, and the AMPs proposed by the applicant are consistent with the GALL Report and contain the commitment recommended in SRP
| |
| -LR Section 3.1.2.2.13.
| |
| Based on its review, the staff concludes that the AMP proposed by the applicant for those items which are currently under consideration meets the criteria contained in SRP
| |
| -LR Section 3.1.2.2.13. Additionally, the staff concludes that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.1.2.2.14 Wall Thinning Due to Flow
| |
| -Accelerated Corrosion LRA Section 3.1.2.2.14 is associated with LRA Table 3.1.1, item 3.1.1
| |
| -32, and addresses the steel steam generator feedwater inlet ring and supports exposed to secondary feedwater and steam, which are being managed for wall thinning due to flow
| |
| -accelerated corrosion by the Steam Generator Tube Integrity Program. The criteria in SRP
| |
| -LR Section 3.1.2.2.14 states that wall thinning due to flow
| |
| -accelerated corrosion could occur for steel feedwater inlet rings and supports. The SRP
| |
| -LR and the GALL Report also state that NRC IN 91
| |
| -19, "Steam Generator Feedwater Distribution Piping Damage," cites evidence of flow
| |
| -accelerated corrosion in steam Aging Management Review Results 3-310 generators and recommends that a plant
| |
| -specific AMP be evaluated because existing programs may not be capable of mitigating or detecting wall thinning due to flow-accelerated corrosion.
| |
| The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that IN 91
| |
| -19 addresses wall thinning due to flow
| |
| -accelerated corrosion in Combustion Engineering
| |
| -designed steam generator feedwater inlet rings and supports, and it is not directly applicable to Seabrook, which uses Westinghouse Model F steam generators. The applicant further stated that it will manage wall thinning due to flow
| |
| -accelerated corrosion in the steel steam generator feedwater inlet rings and supports by using the Steam Generator Tube Integrity Program. The Steam Generator Tube Integrity Program implements many 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 a loss of component intended function.
| |
| The staff's evaluation of the applicant's Steam Generator Tube Integrity Program is documented in SER Section 3.0.3.2.2. In its review of components associated with item 3.1.1
| |
| -32 and the Steam Generator Tube Integrity Program described in LRA Section B.2.1.10, the staff noted that the applicant stated that the program includes management of wall thinning from flow
| |
| -accelerated corrosion of steam generator components. However, the applicant does not describe the inspections or analytical techniques used to ensure that excessive wall thinning due to flow
| |
| -accelerated corrosion does not occur in the components.
| |
| By letter dated January 5, 2011, the staff issued RAI 3.1.2.2.14
| |
| -01, asking the applicant to describe its examination techniques and the evaluation methodology used to manage wall thinning in the steam generator feedwater inlet rings and supports.
| |
| In its response dated February 3, 2011, the applicant stated that the Steam Generator Tube Integrity Program uses visual inspections of the steam generators' secondary
| |
| -side internals, including the steam generator feedwater inlet ring and supports, and does not include predictive analytical methodology for wall thinning due to flow
| |
| -accelerated corrosion. The applicant further stated that it performs a degradation assessment of the steam generators during each RFO, and visual inspections are required for the degradation assessment. The applicant stated that the visual inspections identify the general condition of the steam generator components and allow the search for evidence of erosion
| |
| -corrosion, irregular geometry, and structural changes, and the acceptance criteria require that there be no visible signs of degradation. The applicant stated that its steam generator degradation assessment for the feedwater rings typically includes outside surface, supports, welds, cross
| |
| -over pipe, feedwater nozzle knuckle region, feedwater ring to J
| |
| -nozzle intersection on the outside diameter, J
| |
| -nozzle to feedwater ring joint on the inside diameter, feedwater ring weld backing rings, and all welds. The degradation assessment ensures that degradation of components is identified, and corrective actions are taken before loss of component
| |
| -intended functions.
| |
| The staff finds the applicant's response to RAI 3.1.2.2.14
| |
| -01 acceptable because the applicant met the further evaluation criteria, and the applicant's proposal to manage aging using the Steam Generator Tube Integrity Program is acceptable for the following reasons:
| |
| * The applicant's Steam Generator Tube Integrity Program includes visual inspections of the steel steam generator feedwater inlet rings and supports performed at each RFO.
| |
| | |
| Aging Management Review Results 3-311
| |
| * The visual inspections of the feedwater inlet rings and supports are capable of identifying loss of material and wall thinning that may occur in these components caused by flow-accelerated corrosion.
| |
| * Results of the visual inspections are used as input to a degradation assessment of steam generator components performed during each RFO so that corrective action, if needed, can be implemented before loss of component
| |
| -intended function occurs.
| |
| The staff's concern described in RAI 3.1.2.2.14
| |
| -01 is resolved.
| |
| Based on the program identified, the staff concludes that the applicant's program meets SRP
| |
| -LR Section 3.1.2.2.14 criteria. For those items that apply to LRA Section 3.1.2.2.14, the staff determined that the LRA is consistent with the GALL Report, and the applicant 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 and Table 3.1.1, item 3.1.1
| |
| -33, against criteria in SRP-LR 3.1.2.2.15. LRA Section 3.1.2.2.15 addresses changes in dimensions due to void swelling that could occur in stainless steel and N i-alloy PWR RVI components exposed to reactor coolant. The SRP
| |
| -LR recommends no further AMR if the applicant provides a commitment in the UFSAR supplement to do the following:
| |
| * participate in the industry programs for investigating and managing aging effects on reactor internals
| |
| * evaluate and implement the results of the industry programs as applicable to the reactor internals
| |
| * upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval The staff noted that the applicant's commitment (Commitment
| |
| : 1) in LRA Appendix A, Section A3, is consistent with the commitment described in SRP
| |
| -LR 3.1.2.2.15. The staff also noted that all of the AMR results lines that refer to Table 3.1.1, item 3.1.1.33, are aligned with the applicant's commitment, as described in LRA Appendix A, Section A3. The staff finds the applicant's proposal acceptable because the discussion of the AMR item refers to the applicant's AMP (PWR Vessel Internals Program), which includes the appropriate commitment in the UFSAR supplement.
| |
| Based on its review, the staff concludes that the applicant demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.1.2.2.16 Cracking Due to Stress
| |
| -Corrosion Cracking and Primary Water Stress
| |
| -Corrosion Cracking (1) LRA Section 3.1.2.2.16.1 is associated with LRA Table 3.1.1, items 3.1.1
| |
| -34 and Aging Management Review Results 3-312 3.1.1-35. It addresses stainless steel canopy seal pressure housing and nickel
| |
| -alloy CRD pressure housing exposed to reactor coolant that are being managed for cracking due to SCC and PWSCC by the ASME Code Section XI ISI, Subsection IWB, IWC, and IWD Program and the Water Chemistry Program. The criteria in SRP-LR Section 3.1.2.2.16, item 1, state that cracking due to SCC and PWSCC could occur for steel steam generator components and steam generator tube
| |
| -to-tube sheet welds made or clad with nickel alloy exposed to reactor coolant. The SRP
| |
| -LR also states that the GALL Report recommends ASME Code Section XI ISI and control of water chemistry to manage this aging effect. Additionally, no further AMR of PWSCC of nickel alloys is needed if the applicant complies with applicable NRC Orders and provides a commitment in the UFSAR supplement to implement applicable bulletins, generic letters, and staff-accepted industry guidelines. In its review, the staff noted that the nickel
| |
| -alloy CRD pressure housing is not a reactor vessel head penetration or nozzle for which the further evaluation criterion associated with the NRC Orders and UFSAR supplement is applicable. In addition, the staff noted that GALL Report, Revision 2, item IV.A2.RP
| |
| -55 recommends the ASME Code Section XI ISI, Subsection IWB, IWC, and IWD Program and Water Chemistry Program to manage cracking due to SCC and PWSCC of stainless steel and nickel
| |
| -alloy CRD pressure housings.
| |
| By letter dated November 15, 2010, the applicant submitted Supplement 2 to the LRA. As described in this document, LRA Section 3.1.2.2.16.1 addresses the further evaluation criteria of the SRP
| |
| -LR by stating that the GALL Report, Revision 1, recommends a commitment in the UFSAR supplement to implement applicable bulletins and letters and staff
| |
| -accepted industry guidelines, which is met by crediting its Nickel
| |
| -Alloy Nozzles and Penetrations Program to manage PWSCC of the nickel
| |
| -alloy nozzles and penetrations. The applicant also clarified that the commitment recommended by the SRP
| |
| -LR is associated with the Nickel
| |
| -Alloy Nozzles a nd Penetrations Program. However, the Nickel
| |
| -Alloy Nozzles and Penetrations Program is not applicable to the nickel
| |
| -alloy CRD pressure housing because the component is not a penetration or nozzle. The applicant further stated that cracking due to SCC and PWSCC of the CRD pressure housings is being managed by the ASME Code Section XI ISI, Subsection IWB, IWC, and IWD Program and Water Chemistry Program. The staff finds the applicant's claim acceptable because the applicant's use of the ASME Code Section XI ISI, Subsection IWB, IWC, and IWD Program and Water Chemistry Program is sufficient to manage SCC of the nickel
| |
| -alloy CRD pressure housing, as evaluated below. The staff's evaluations of the applicant's ASME Code Section XI ISI, Subsection IWB, IWC, and IWD Program and Water Chemistry Program are documented in SER Sections 3.0.3.1.1 and 3.0.3.1.2, respectively. In its review of components associated with item 3.1.1
| |
| -34, the staff finds that the applicant met the further evaluation criteria and the applicant's proposal to manage aging using the ASME Code Section XI ISI, Subsection IWB, IWC, and IWD Program and Water Chemistry Program is acceptable for the following reasons:
| |
| * The Water Chemistry Program establishes the plant water chemistry control parameters, and their limits to mitigate an environment that is conducive for cracking and takes corrective actions if the parameters exceed these limits.
| |
| | |
| Aging Management Review Results 3-313
| |
| * The ASME Code Section XI ISI, Subsection IWB, IWC, and IWD Program is adequate to detect and manage cracking of these components, consistent with the GALL Report.
| |
| * The use of the Water Chemistry Program in conjunction with the ASME Code Section XI ISI, Subsection IWB, IWC, and IWD Program is sufficient to manage cracking due to SCC of the components through periodic inspections and water chemistry control.
| |
| LRA Section 3.1.2.2.16, item 1, also states that LRA Table 3.1.1, item 3.1.1
| |
| -35, is not applicable because the plant does not have OTSGs and, therefore, does not have the components associated with these steam generators.
| |
| By letter dated December 14, 2010, the staff also issued RAI B.2.1.10
| |
| -1 to request additional information regarding the applicant's steam generator tube
| |
| -to-tubesheet welds, The applicant provided a response by letter dated January 13, 2011, to clarify the dispositioning of its tube
| |
| -to-tubesheet welds with respect to its RCPB and to also explain how it will manage cracking due to SCC and PWSCC of the steam generator tube sheets and tube
| |
| -to-tubesheet welds made of steel with nickel
| |
| -alloy cladding. The staff's evaluation of the applicant's response to RAI B.2.1.10
| |
| -1 is documented in SER Section 3.0.3.2.2, and Open Item OI 3.0.3.2.2
| |
| -1 was identified for the applicant to provide additional information regarding aging management of the welds. Resolution for OI 3.0.3.2.2-1 is documented in Section 3.0.3.2.2.
| |
| Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.16, item 1, criteria. For those items that apply to LRA Section 3.1.2.2.16.1, the staff determined that the LRA is consistent with the GALL Report and that the applicant 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). (2) LRA Section 3.1.2.2.16.2 is associated with LRA Table 3.1.1, item 3.1.1
| |
| -36, and addresses nickel alloy and stainless steel pressurizer spray heads exposed to reactor coolant that are being managed for cracking due to SCC for stainless steel components and PWSCC for nickel
| |
| -alloy components by the Water Chemistry and One
| |
| -Time Inspection Programs. SRP
| |
| -LR Section 3.1.2.2.16, item 2, states that cracking due to SCC could occur on stainless steel pressurizer spray heads, and cracking due to PWSCC could occur on nickel
| |
| -alloy pressurizer spray heads. The SRP
| |
| -LR also states that the existing program relies on control of water chemistry to mitigate this aging effect.
| |
| The GALL Report recommends one
| |
| -time inspection to confirm that cracking does not occur. Furthermore, for nickel
| |
| -alloy welded spray heads, the GALL Report recommends no further AMR if the applicant complies with applicable NRC Orders and provides a commitment in the UFSAR supplement to implement applicable bulletins, generic letters, and staff-accepted industry guidelines. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that it will implement the One
| |
| -Time Inspection Program to verify the effectiveness of the Water Chemistry Program to manage cracking due to SCC in the stainless steel pressurizer spray head exposed to reactor coolant.
| |
| The staff's evaluations of the applicant's Water Chemistry and One
| |
| -Time Inspection Programs are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. In Aging Management Review Results 3-314 these evaluations, the staff found these programs to be acceptable means to manage aging. In its review of components associated with LRA Table 3.1.1, item 3.1.1
| |
| -36, the staff noted that all of the associated components were constructed from stainless steel (i.e., there are no nickel
| |
| -alloy components included in this AMR item). The staff, therefore, finds that the applicant met the further evaluation criteria. The applicant's proposal to manage aging using the Water Chemistry and One
| |
| -Time Inspection Programs is acceptable for the following reasons:
| |
| * The applicant's proposed programs are consistent with those recommended by LRA Section 3.1.2.2.16, item 2, for stainless steel components.
| |
| * The Water Chemistry and One
| |
| -Time Inspection Programs were evaluated by the staff and found to be acceptable to manage aging.
| |
| * There are no nickel
| |
| -alloy components included in this AMR item, making the provisions of LRA Section 3.1.2.2.16, item 2, which apply to nickel
| |
| -alloy components, not applicable.
| |
| Based on its review, the staff concludes that the aging management proposed by the applicant for those items which are currently under consideration meets the criteria contained in item 2 of SRP
| |
| -LR Section 3.1.2.2.16. The staff concludes 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 Irradiated
| |
| -Assisted Stress
| |
| -Corrosion Cracking The staff reviewed LRA Section 3.1.2.2.17 and Table 3.1.1, item 3.1.1
| |
| -37, against the criteria in SRP-LR 3.1.2.2.17, which addresses cracking due to SCC, PWSCC, and IASCC that could occur in stainless steel and Ni
| |
| -alloy PWR reactor internal components exposed to reactor coolant. LRA Section 3.1.2.2.17 noted that the existing program relies on control of water chemistry to mitigate cracking due to SCC, PWSCC, and IASCC of these PWR reactor internals components exposed to reactor coolant. SRP
| |
| -LR 3.1.2.2.17 recommends no further AMR if the applicant provides a commitment in the UFSAR supplement to do the following:
| |
| * participate in the industry programs for investigating and managing aging effects on reactor internals
| |
| * evaluate and implement the results of the industry programs as applicable to the reactor internals
| |
| * upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval The staff noted that the applicant's commitment (Commitment 1) in LRA Appendix A, Section A3, is consistent with the commitment described in SRP
| |
| -LR 3.1.2.2.17. The staff also noted Aging Management Review Results 3-315 that all of the AMR results lines that refer to Table 3.1.1, item 3.1.1
| |
| -37, align with the applicant's commitment as described in LRA Appendix A, Section A3. The staff finds the applicant's proposal acceptable because the discussion of the AMR item refers to the applicant's AMP (PWR Vessel Internals Program), which includes the appropriate commitment in the UFSAR supplement.
| |
| In LRA Section 3.1.2.2.17, the applicant stated that, for managing the aging of cracking due to SCC, PWSCC, and IASCC of stainless steel and nickel
| |
| -alloy reactor internals components exposed to reactor coolant, the applicant's Water Chemistry Program is augmented by the commitment described above. When augmented by the commitment above, the staff finds the applicant's Water Chemistry Program acceptable for managing SCC and IASCC of stainless steel reactor internals components exposed to reactor coolant because the Water Chemistry Program will control contaminants that can contribute to SCC of stainless steel.
| |
| The staff's evaluation of the applicant's Water Chemistry Program is documented in SER Section 3.0.3.1.2. In its review of components associated with item 3.1.1
| |
| -37, the staff finds the applicant's proposal to manage aging using the Water Chemistry Program acceptable because use of the Water Chemistry Program to manage cracking is consistent with the GALL Report when combined with the commitment described above.
| |
| Based on the programs identified, the staff concludes that the applicant's program meets SRP
| |
| -LR Section 3.1.2.2.17 criteria. For those items that apply to LRA Section 3.1.2.2.17, the staff determined that the LRA is consistent with the GALL Report and that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.1.2.2.18 Quality Assurance for Aging Management of Nonsafety
| |
| -Related Components SER Section 3.0.4 provides the staff's evaluation of the applicant's QA Program.
| |
| 3.1.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report In LRA Tables 3.1.2
| |
| -1 through 3.1.2
| |
| -4, the staff reviewed additional details of AMR results for material, environment, AERM, and AMP combinations not consistent with or not addressed in the GALL Report.
| |
| In LRA Tables 3.1.2-1 through 3.1.2
| |
| -4, the applicant indicated, via Notes F
| |
| -J, that the combination of component type, material, environment, and AERM does not correspond to an item in the GALL Report. The applicant provided further information concerning how the aging effects will be managed. Specifically, Note F indicates that the material for the AMR item component is not evaluated in the GALL Report. Note G indicates that the environment for the AMR item component and material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR item component, material, and environment combination is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the item component, material, and environment combination is not applicable. Note J indicates that neither the component nor the material and environment combination for the item is evaluated in the GALL Report.
| |
| | |
| Aging Management Review Results 3-316 For component type, material, and environment combinations not evaluated in the GA LL Report, the staff reviewed the applicant's evaluation to determine if the applicant demonstrated that the aging effects will be adequately managed so that the intended functions will be maintained consistent with the CLB during the period of extended operation. The staff's evaluation is discussed in the following sections.
| |
| 3.1.2.3.1 Reactor Coolant System, Summary of Aging Management Evaluation, LRA Table 3.1.2-1 In LRA Tables 3.1.2
| |
| -1, 3.1.2-2, 3.1.2-3, and 3.1.2
| |
| -4, the applicant stated that for Ni
| |
| -alloy components exposed to air with borated water leakage, there is no aging effect, and no AMP is proposed. The AMR items cite generic Note G and plant
| |
| -specific Note 1. Plant
| |
| -specific Note 1 states the following:
| |
| NUREG-1801 does not include air with borated water leakage for nickel
| |
| -alloy components. Similar to V.F
| |
| -13 for stainless steel, there are no aging effects for nickel alloy in air with borated water leakage. Additionally, the American Welding Society (AWS) "Welding Handbook," (Seventh Edition, Volume 4, 1982, Library of Congress) identifies that nickel chromium alloy materials that are alloyed with iron, molybdenum, tungsten, cobalt or copper in various combinations have improved corrosion resistance.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant's use of generic Note G for these items is appropriate in that the GALL Report, Revision 1, does not include entries for nickel alloys exposed to air with borated water leakage. The staff noted that the GALL Report, Revision 2, dated December 2010, includes entries for nickel alloys exposed to air with borated water leakage. These entries indicate that no AERM is present for this material-environment combination. The staff also noted these items in the GALL Report , Revision 2, are based in part on EPRI Report 1000975, "Boric Acid Corrosion Guidebook, Revision 1." This report contains data (pages 4
| |
| -43) showing that "[t]here was no measurable corrosion of stainless steel piping surfaces or Inconel weld metal joining the stainless steel and carbon steel piping sections." The staff, therefore, concurs with the applicant's assessment that aging management is not necessary for nickel
| |
| -alloy components exposed to air with borated water leakage, as described above.
| |
| In LRA Table 3.1.2
| |
| -1, the applicant stated that the AERM for CASS RCS piping and fittings exposed to reactor coolant (internal) greater than 482 °F (250 °C), which is susceptible to loss of fracture toughness due to thermal aging embrittlement, is not applicable, and no AMP is proposed. The AMR item cites generic Note I. The applicant addressed the CASS piping and fitting components in LRA Table 3.1.2
| |
| -1 for the RCS and related these components to LRA item 3.1.1-57. The applicant also stated that these components have molybdenum and ferrite contents below the threshold for susceptibility to thermal aging embrittlement.
| |
| The staff reviewed the associated items in the LRA and confirmed that loss of fracture toughness due to thermal aging embrittlement is not applicable to the component, material and environment combination. LRA Table 3.1.1, item 3.1.1
| |
| -57, indicates that the molybdenum and ferrite contents for this component are below the threshold (less than 0.5
| |
| -percent molybdenum and less than 20
| |
| -percent ferrite), such that the components are not susceptible to this aging effect, consistent with GALL Report AMP XI.M12.
| |
| | |
| Aging Management Review Results 3-317 The staff also noted that UFSAR Table 5.2
| |
| -2 indicates that the piping in the RCS is made of SA-376, Grade 304N, or centrifugally
| |
| -cast SA-351, Grade CF8A. The staff noted that SA
| |
| -376, Grade 304N, material is not a CASS material and, therefore, finds that this material is not susceptible to thermal aging embrittlement, consistent with the GALL Report. The staff also finds that centrifugally
| |
| -cast SA-351, Grade CF8A, is a low
| |
| -molybdenum CASS material, which is not susceptible to thermal aging embrittlement, consistent with the GALL Report AMP XI.M12. In a teleconference held on March 3, 2011, the applicant further clarified that the reactor coolant piping, described in UFSAR Table 5.2
| |
| -2, is made of SA
| |
| -376, Grade 304N, material, and the listed centrifugal casting material has not been used for the reactor coolant piping. In LRA Table 3.1.2
| |
| -1, the applicant stated that the stainless steel bolting exposed to air-indoor is being managed for loss of preload by the Bolting Integrity Program. The AMR item cites generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination because, even though stainless steel bolting exposed to air
| |
| -indoor is not specifically addressed in the GALL Report, Table IX.E of the GALL Report states that loss of preload can occur independent of environmental conditions because it can be caused by thermal or mechanical effects. Additionally, Table IX.C of the GALL Report states that stainless steel material is susceptible to a variety of aging effects and mechanisms, including loss of material due to pitting and crevice corrosion and cracking due to SCC. The staff noted that the environment of interest, air
| |
| -indoor, would not induce SCC or loss of material in stainless steel material because stainless steel is inherently resistant to corrosion in the air
| |
| -indoor environment. Therefore, the aging effect of concern is loss of preload, which is addressed in the AMR.
| |
| The staff's evaluation of the applicant's Bolting Integrity Program is documented in SER Section 3.0.3.1.7. While there is no AMR for stainless steel bolting exposed to air
| |
| -indoor in the RCS, the GALL Report has items for other material bolting exposed to air
| |
| -indoor managed by the Bolting Integrity Program. The staff finds the applicant's proposal to manage aging using the Bolting Integrity Program acceptable because the Bolting Integrity Program conducts bolting assembly and maintenance control such as application of appropriate gasket alignment, torque, lubricants, and preload. It also inspects for leakage and loose or missing nuts, which verify that the aging effect, loss of preload, will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging for thes e components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.1.2.3.2 Reactor Vessel, Summary of Aging Management Evaluation, LRA Table 3.1.2
| |
| -2 The staff's evaluation for Ni
| |
| -alloy components exposed to borated water leakage that are not subject to an aging effect requiring management, with generic Note G, is documented in SER Section 3.1.2.3.1.
| |
| | |
| Aging Management Review Results 3-318 On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.1.2.3.3 Reactor Vessel Internals, Summary of Aging Management Evaluation, LRA Table 3.1.2-3 Table 3.1.2
| |
| -3, "Reactor Vessel Internals, Summary of Aging Management Evaluation," item 366, addresses Ni
| |
| -Alloy flux thimble tubes exposed to air with borated water leakage (internal) and assigns Note G to this component. The staff's evaluation for Ni
| |
| -alloy components exposed to borated water leakage that are not subject to an aging effect requiring management, with generic Note G, is documented in SER Section 3.1.2.3.1.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.1.2.3.4 Steam Generator, Summary of Aging Management Evaluation, LRA Table 3.1.2
| |
| -4 In LRA Table 3.1.2
| |
| -4, the applicant stated that the nickel
| |
| -alloy steam generator tubes exposed to reactor coolant are being managed for reduction of heat transfer by the Water Chemistry Program. The AMR item cites generic Note H. The AMR items also cite plant-specific Note 4, which states that reduction of heat transfer due to fouling is not in the GALL Report for this component, material, and environment but that reduction of heat transfer is applicable to this combination and, therefore, will be managed by the Water Chemistry Program.
| |
| The staff reviewed the associated items in the LRA. However, it was not clear to the staff how the Water Chemistry Program alone would ensure that reduction of heat transfer is appropriately managed. Typically, for reduction of heat transfer, both a Water Chemistry Program and an Inspection Program are used to manage this aging effect. By letter date January 5, 2011, the staff issued RAI 3.1.2.4
| |
| -1, requesting that the applicant justify how the Water Chemistry Program alone is sufficient to determine that steam generator tubes are not affected by reduction of heat transfer when exposed to reactor coolant.
| |
| In its response dated February 3, 2011, the applicant stated that reduction of heat transfer due to fouling was inadvertently added as an AMR item and that neither plant
| |
| -specific nor any industry operating experience has indicated that this aging effect is applicable to steam generator tubes exposed to reactor coolant. The applicant has removed the AMR item from the LRA. The staff finds the applicant's response acceptable because reduction of heat transfer due to fouling for tubes internally exposed to reactor coolant is not an aging affect that has been observed in steam generators, which is consistent with the GALL Report. The staff's concern described in RAI 3.1.2.4
| |
| -1 is resolved.
| |
| | |
| Aging Management Review Results 3-319 In LRA Table 3.1.2
| |
| -4, the applicant stated that the nickel
| |
| -alloy steam generator tubes exposed to secondary feedwater or steam are being managed for reduction of heat transfer by the Water Chemistry Program and Steam Generator Tube Integrity Program. The AMR item cites generic Note H. The AMR items also cite plant
| |
| -specific Note 3, which states that reduction of heat transfer due to fouling is not in the GALL Report for this component, material, and environment, but that reduction of heat transfer is applicable to this combination and, therefore, will be managed by the Water Chemistry Program and Steam Generator Tube Integrity Program.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination because steam generator tubes are likely places where fouling can occur due to buildup of corrosion products, and evidence of fouling has been shown to occur in certain locations in the steam generators (ASM International, Environments and Industries, pp. 362-385, 2006).
| |
| The staff's evaluations of the applicant's Water Chemistry Program and Steam Generator Tube Integrity Program are documented in SER Sections 3.0.3.1.2 and 3.0.3.2.2, respectively. The staff noted that the Water Chemistry Program relies upon periodic monitoring and control of detrimental contaminants in the water to manage reduction of heat transfer. The staff also noted that the Steam Generator Tube Integrity Program uses visual inspections to evaluate sludge buildup and other corrosion phenomena. The staff finds the applicant's proposal to manage aging using the Water Chemistry Program and Steam Generator Tube Integrity Program acceptable because the maintenance of water chemistry will prevent buildup of products that can lead to reduction of heat transfer, and the visual inspections will be able to identify the occurrence of fouling that could lead to a reduction of heat transfer.
| |
| The staff's evaluation for Ni
| |
| -alloy components exposed to borated water leakage that are not subject to an aging effect requiring management, with generic Note G, is documented in SER Section 3.1.2.3.1.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| | |
| ====3.1.3 Conclusion====
| |
| | |
| The staff concludes that the applicant provided sufficient information to demonstrate that the effects of aging for the reactor vessel, RVIs, RCS, and steam generator components, within the scope of license renewal and subject to an AMR, will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| | |
| ===3.2 Aging===
| |
| Management of Engineered Safety Features This section of the SER documents the staff's review of the applicant's AMR results for the ESFs systems components and component groups of the following systems:
| |
| * combustible gas control system
| |
| | |
| Aging Management Review Results 3-320
| |
| * containment building spray system
| |
| * RH system
| |
| * SI system
| |
| | |
| ====3.2.1 Summary====
| |
| of Technical Information in the Application LRA Section 3.2 provides AMR results for the engineered safety features (ESF) systems' components. LRA Table 3.2.1, "Summary of Aging Management Evaluation for Engineered Safety Features," is a summary comparison of the applicant's AMRs with those evaluated in the GALL Report for the ESF components and component groups.
| |
| The applicant's AMRs evaluated and incorporated applicable plant
| |
| -specific and industry operating experience in the determination of AERMs. The plant
| |
| -specific evaluation included condition reports and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a review of the GALL Report and operating experience issues identified since the issuance of the GALL Report. 3.2.2 Staff Evaluation The staff reviewed LRA Section 3.2 to determine if the applicant provided sufficient information to demonstrate that the effects of aging for the ESF systems' components, within the scope of license renewal and subject to an AMR, will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| The staff conducted an onsite audit of AMRs to ensure the applicant's claim that certain AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's audit evaluation are documented in SER Section 3.2.2.1.
| |
| In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which further evaluation is recommended. The staff confirmed that the applicant's further evaluations were consistent with the SRP
| |
| -LR Section 3.2.2.2 acceptance criteria. The staff's audit evaluations are documented in SER Section 3.2.2.2.
| |
| The staff also conducted a technical review of the remaining AMRs not consistent with or not addressed in the GALL Report. The technical review evaluated whether all plausible aging effects have been identified and whether the aging effects listed were appropriate for the material-environment combinations specified. The staff's evaluations are documented in SER Section 3.2.2.3.
| |
| For SSCs which the applicant claimed were not applicable or required no aging management, the staff reviewed the AMR items and the plant's operating experience to verify the applicant's claims. Table 3.2-1 summarizes the staff's evaluation of components, aging effects or mechanisms, and AMPs listed in LRA Section 3.2 and addressed in the GALL Report.
| |
| | |
| Aging Management Review Results 3-321 Table 3.2-1. Staff Evaluation for Engineered Safety Features Systems Components in the GALL Report Component group (GALL Report Item No.)
| |
| Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Steel and stainless steel piping, piping components, and piping elements in ECCS (3.2.1-1) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c)
| |
| Yes TLAA Consistent with GALL Report (see SER Section 3.2.2.2.1)
| |
| Steel with stainless steel cladding pump casing exposed to treated borated water (3.2.1-2) Loss of material due to cladding breach A plant-specific AMP is to be evaluated.
| |
| Reference NRC IN 94-63, "Boric Acid Corrosion of Charging Pump Casings Caused by Cladding Cracks" Yes Not applicable Not applicable to Seabrook (see SER Section 3.2.2.2.2)
| |
| Stainless steel containment isolation piping and components internal surfaces exposed to treated water (3.2.1-3) Loss of material due to pitting and crevice corrosion Water Chemistry and One-Time Inspection Yes Water Chemistry and One-Time Inspection Consistent with GALL Report (see SER Section 3.2.2.2.3)
| |
| Stainless steel piping, piping components, and piping elements exposed to soil (3.2.1-4) Loss of material due to pitting and crevice corrosion A plant-specific AMP is to be evaluated.
| |
| Yes Not applicable Not applicable to Seabrook (see SER Section 3.2.2.2.3)
| |
| Component group (GALL Report Item No.)
| |
| Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Stainless steel and aluminum piping, piping components, and piping elements exposed to treated water (3.2.1-5) Loss of material due to pitting and crevice corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (see SER Section 3.2.2.2.3)
| |
| | |
| Aging Management Review Results 3-322 Stainless steel and copper-alloy piping, piping components, and piping elements exposed to lubricating oil (3.2.1-6) Loss of material due to pitting and crevice corrosion Lubricating Oil Analysis and One
| |
| - Time Inspection Yes Lubricating Oil Analysis and One-Time Inspection Consistent with GALL Report (see SER Section 3.2.2.2.3)
| |
| Partially encased stainless steel tanks with breached moisture barrier exposed to raw water (3.2.1-7) Loss of material due to pitting and crevice corrosion A plant-specific AMP is to be evaluated for pitting and crevice corrosion of tank bottoms because moisture and water can egress under the tank due to cracking of the perimeter seal from weathering.
| |
| Yes Not applicable Not applicable to Seabrook (see SER Section 3.2.2.2.3)
| |
| Stainless steel piping, piping components, piping elements, and tank internal surfaces exposed to condensation (internal)
| |
| (3.2.1-8) Loss of material due to pitting and crevice corrosion A plant-specific AMP is to be evaluated.
| |
| Yes Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Not applicable to Seabrook (see SER Section 3.2.2.2.3)
| |
| Steel, stainless steel, and copper
| |
| -alloy heat exchanger tubes exposed to lubricating oil (3.2.1-9) Reduction of heat transfer due to fouling Lubricating Oil Analysis and One
| |
| - Time Inspection Yes Lubricating Oil Analysis and One-Time Inspection Consistent with GALL Report (see SER Section 3.2.2.2.4)
| |
| Stainless steel heat exchanger tubes exposed to treated water (3.2.1-10)* Reduction of heat transfer due to fouling Water Chemistry and One-Time Inspection Yes Water Chemistry and One-Time Inspection Consistent with GALL Report (see SER Section 3.2.2.2.4)
| |
| Component group (GALL Report Item No.)
| |
| Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Elastomer seals and components in standby gas treatment system exposed to air
| |
| - indoor uncontrolled (3.2.1-11) Hardening and loss of strength due to elastomer degradation A plant-specific AMP is to be evaluated.
| |
| Yes Not applicable Not applicable to PWRs (see SER Section 3.2.2.2.5)
| |
| | |
| Aging Management Review Results 3-323 Stainless steel high- pressure safety injection (HPSI) (charging) pump miniflow orifice exposed to treated borated water (3.2.1
| |
| -12) Loss of material due to erosion A plant-specific AMP is to be evaluated for erosion of the orifice due to extended use of the centrifugal HPSI pump for normal charging.
| |
| Yes Not applicable Consistent with GALL Report (see SER Section 3.2.2.2.6)
| |
| Steel drywell and suppression chamber spray system nozzle and flow orifice internal surfaces exposed to air-indoor uncontrolled (internal)
| |
| (3.2.1-13) Loss of material due to general corrosion and fouling A plant-specific AMP is to be evaluated.
| |
| Yes Not applicable Not applicable to PWRs (see SER Section 3.2.2.2.7)
| |
| Steel piping, piping components, and piping elements exposed to treated water (3.2.1
| |
| -14) Loss of material due to general, pitting, and crevice corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (see SER Section 3.2.2.2.8)
| |
| Steel containment isolation piping, piping components, and piping elements internal surfaces exposed to treated water (3.2.1
| |
| -15) Loss of material due to general, pitting, and crevice corrosion Water Chemistry and One-Time Inspection Yes Water Chemistry and One-Time Inspection Not applicable to Seabrook (see SER Section 3.2.2.2.8)
| |
| Steel piping, piping components, and piping elements exposed to lubricating oil (3.2.1-16) Loss of material due to general, pitting, and crevice corrosion Lubricating Oil Analysis and One
| |
| - Time Inspection Yes Lubricating Oil Analysis and One-Time Inspection Consistent with GALL Report (see SER Section 3.2.2.2.8)
| |
| Component group (GALL Report Item No.)
| |
| Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Steel (with or without coating or wrapping) piping, piping components, and piping elements buried in soil (3.2.1-17) Loss of material due to general, pitting, crevice, and microbiologically
| |
| -influenced corrosion (MIC) Buried Piping and Tanks Surveillance or Buried Piping and Tanks Inspection No Yes Not applicable Not applicable to Seabrook (see SER Section 3.2.2.2.9)
| |
| | |
| Aging Management Review Results 3-324 Stainless steel piping, piping components, and piping elements exposed to treated water > 140 °F (> 60 °C)
| |
| (3.2.1-18) Cracking due to SCC and IGSCC BWR SCC and Water Chemistry No Not applicable Not applicable to PWRs (see SER Section 3.2.2.1.1)
| |
| Steel piping, piping components, and piping elements exposed to steam or treated water (3.2.1-19) Wall thinning due to flow- accelerated corrosion Flow-Accelerated Corrosion No Not applicable Not applicable to PWRs (see SER Section 3.2.2.1.1)
| |
| CASS piping, piping components, and piping elements exposed to treated water (borated or unborated) > 482
| |
| °F (> 250 °C)
| |
| (3.2.1-20) Loss of fracture toughness due to thermal aging embrittlement Thermal Aging Embrittlement of CASS No Not applicable Not applicable to PWRs (see SER Section 3.2.2.1.1)
| |
| High-strength steel closure bolting exposed to air with steam or water leakage (3.2.1-21) Cracking due to cyclic loading and SCC Bolting Integrity No Not applicable Not applicable to Seabrook (see SER Section 3.2.2.1.1)
| |
| Steel closure bolting exposed to air with steam or water leakage (3.2.1-22) Loss of material due to general corrosion Bolting Integrity No Not applicable Not applicable to Seabrook (see SER Section 3.2.2.1.1)
| |
| Steel bolting and closure bolting exposed to air
| |
| - outdoor (external), or air
| |
| -indoor uncontrolled (external)
| |
| (3.2.1-23) Loss of material due to general, pitting, and crevice corrosion Bolting Integrity No Bolting Integrity Consistent with GALL Report Component group (GALL Report Item No.)
| |
| Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation
| |
| | |
| Aging Management Review Results 3-325 Steel closure bolting exposed to air- indoor uncontrolled (external)
| |
| (3.2.1-24) Loss of preload due to thermal effects, gasket creep, and self-loosening Bolting Integrity No Bolting Integrity Consistent with GALL Report Stainless steel piping, piping components, and piping elements exposed to closed
| |
| -cycle cooling water
| |
| > 140 °F (>60 °C) (3.2.1-25) Cracking due to SCC Closed-Cycle Cooling Water System No Closed-Cycle Cooling Water System Consistent with GALL Report Steel piping, piping components, and piping elements exposed to closed
| |
| -cycle cooling water (3.2.1-26) Loss of material due to general, pitting, and crevice corrosion Closed-Cycle Cooling Water System No Closed-Cycle Cooling Water System Consistent with GALL Report Steel heat exchanger components exposed to closed
| |
| -cycle cooling water (3.2.1-27) Loss of material due to general, pitting, crevice, and galvanic corrosion Closed-Cycle Cooling Water System No Closed-Cycle Cooling Water System Consistent with GALL Report Stainless steel piping, piping components, piping elements, and heat exchanger components exposed to closed
| |
| - cycle cooling water (3.2.1-28) Loss of material due to pitting and crevice corrosion Closed-Cycle Cooling Water System No Closed-Cycle Cooling Water System Consistent with GALL Report Copper-alloy piping, piping components, piping elements, and heat exchanger components exposed to closed
| |
| -cycle cooling water (3.2.1-29) Loss of material due to pitting, crevice, and galvanic corrosion Closed-Cycle Cooling Water System No Closed-Cycle Cooling Water System Consistent with GALL Report
| |
| | |
| Aging Management Review Results 3-326 Component group (GALL Report Item No.)
| |
| Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Stainless steel and copper-alloy heat exchanger tubes exposed to closed
| |
| -cycle cooling water (3.2.1
| |
| -30) Reduction of heat transfer due to fouling Closed-Cycle Cooling Water System No Closed-Cycle Cooling Water System Consistent with GALL Report External surfaces of steel components including ducting, piping, ducting closure bolting, and containment isolation piping external surfaces exposed to air
| |
| - indoor uncontrolled (external); condensation (external) and air- outdoor (external)
| |
| (3.2.1-31) Loss of material due to general corrosion External Surfaces Monitoring No External Surfaces Monitoring Consistent with GALL Report Steel piping and ducting components and internal surfaces exposed to air
| |
| -indoor uncontrolled (Internal)
| |
| (3.2.1-32) Loss of material due to general corrosion Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components No Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components and Fire Water System Consistent with GALL Report (and for Fire Water System Program, see SER Section 3.2.2.1.4)
| |
| Steel encapsulation components exposed to air
| |
| - indoor uncontrolled (internal)
| |
| (3.2.1-33) Loss of material due to general, pitting, and crevice corrosion Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components No Not applicable Not applicable to Seabrook (see SER Section 3.2.2.1.1)
| |
| Steel piping, piping components, and piping elements exposed to condensation (internal)
| |
| (3.2.1-34) Loss of material due to general, pitting, and crevice corrosion Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components No Not applicable Not applicable to Seabrook (see SER Section 3.2.2.1.1)
| |
| | |
| Aging Management Review Results 3-327 Steel containment isolation piping and components internal surfaces exposed to raw water (3.2.1
| |
| -35) Loss of material due to general, pitting, crevice, and microbiologically
| |
| -influenced corrosion, and fouling Open-Cycle Cooling Water System No Fire Water System Consistent with GALL Report (see SER Section 3.2.2.1.2)
| |
| Component group (GALL Report Item No.)
| |
| Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Steel heat exchanger components exposed to raw water (3.2.1
| |
| -36) Loss of material due to general, pitting, crevice, galvanic, and MIC, and fouling Open-Cycle Cooling Water System No Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Not applicable to Seabrook (see SER Section 3.2.2.1.1)
| |
| Stainless steel piping, piping components, and piping elements exposed to raw water (3.2.1
| |
| -37) Loss of material due to pitting, crevice, and MIC Open-Cycle Cooling Water System No Not applicable Not applicable to Seabrook (see SER Section 3.2.2.1.1)
| |
| Stainless steel containment isolation piping and components internal surfaces exposed to raw water (3.2.1
| |
| -38) Loss of material due to pitting, crevice, and MIC, and fouling Open-Cycle Cooling Water System No Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program Consistent with GALL Report (see SER Section 3.2.2.1.3)
| |
| Stainless steel heat exchanger components exposed to raw water (3.2.1
| |
| -39) Loss of material due to pitting, crevice, and MIC, and fouling Open-Cycle Cooling Water System No Fire Water System Program Consistent with GALL Report (see SER Section 3.2.2.1.3)
| |
| Steel and stainless steel heat exchanger tubes (serviced by open- cycle cooling water) exposed to raw water (3.2.1
| |
| -40) Reduction of heat transfer due to fouling Open-Cycle Cooling Water System No Not applicable Not applicable to Seabrook (see SER Section 3.2.2.1.1)
| |
| | |
| Aging Management Review Results 3-328 Copper-alloy > 15% Zn piping, piping components, piping elements, and heat exchanger components exposed to closed
| |
| -cycle cooling water (3.2.1
| |
| -41) Loss of material due to selective leaching Selective Leaching of Materials No Selective Leaching of Materials Consistent with GALL Report Gray cast iron piping, piping components, and piping elements exposed to closed
| |
| - cycle cooling water (3.2.1-42) Loss of material due to selective leaching Selective Leaching of Materials No Not applicable Not applicable to Seabrook (see SER Section 3.2.2.1.1)
| |
| Component group (GALL Report Item No.)
| |
| Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Gray cast iron piping, piping components, and piping elements exposed to soil (3.2.1-43) Loss of material due to selective leaching Selective Leaching of Materials No Not applicable Not applicable to Seabrook (see SER Section 3.2.2.1.1)
| |
| Gray cast iron motor cooler exposed to treated water (3.2.1
| |
| -44) Loss of material due to selective leaching Selective Leaching of Materials No Not applicable Not applicable to Seabrook (see SER Section 3.2.2.1.1)
| |
| Aluminum, copper-alloy > 15% Zn, and steel external surfaces, bolting, and piping, piping components, and piping elements exposed to air with borated water leakage (3.2.1
| |
| -45) Loss of material due to boric acid corrosion Boric Acid Corrosion No Boric Acid Corrosion Consistent with GALL Report Steel encapsulation components exposed to air with borated water leakage (internal)
| |
| (3.2.1-46) Loss of material due to general, pitting, crevice, and boric acid corrosion Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components No Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Consistent with GALL Report
| |
| | |
| Aging Management Review Results 3-329 CASS piping, piping components, and piping elements exposed to treated borated water
| |
| > 482 °F (>250 °C
| |
| ) (3.2.1-47) Loss of fracture toughness due to thermal aging embrittlement Thermal Aging Embrittlement of CASS No Not applicable Not applicable to Seabrook (see SER Section 3.2.2.1.1)
| |
| Stainless steel or stainless-steel-cla d steel piping, piping components, piping elements, and tanks (including SI tanks/accumulator s) exposed to treated borated water > 140 °F (> 60 °C) (3.2.1-48) Cracking due to SCC Water Chemistry No Water Chemistry and One-Time Inspection Consistent with GALL Report Component group (GALL Report Item No.)
| |
| Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Stainless steel piping, piping components, piping elements, and tanks exposed to treated borated water (3.2.1-49) Loss of material due to pitting and crevice corrosion Water Chemistry No Water Chemistry and One-Time Inspection Consistent with GALL Report Aluminum piping, piping components, and piping elements exposed to air
| |
| - indoor uncontrolled (internal/external)
| |
| (3.2.1-50) None None No None Consistent with GALL Report Galvanized steel ducting exposed to air-indoor controlled (external)
| |
| (3.2.1-51) None None No None Consistent with GALL Report
| |
| | |
| Aging Management Review Results 3-330 Glass piping elements exposed to air-indoor uncontrolled (external), lubricating oil, raw water, treated water, or treated borated water (3.2.1-52) None None No None Consistent with GALL Report Stainless steel, copper-alloy, and nickel-alloy piping, piping components, and piping elements exposed to air
| |
| - indoor uncontrolled (external)
| |
| (3.2.1-53) None None No None Consistent with GALL Report Steel piping, piping components, and piping elements exposed to air
| |
| - indoor controlled (external)
| |
| (3.2.1-54) None None No Not applicable Not applicable to Seabrook (see SER Section 3.2.2.1.1)
| |
| Component group (GALL Report Item No.)
| |
| Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Steel and stainless steel piping, piping components, and piping elements in concrete (3.2.1
| |
| -55) None None No Not applicable Not applicable to Seabrook (see SER Section 3.2.2.1.1)
| |
| Steel, stainless steel, and copper
| |
| -alloy piping, piping components, and piping elements exposed to gas (3.2.1-56) None None No None Consistent with GALL Report
| |
| | |
| Aging Management Review Results 3-331 Stainless steel and copper
| |
| -alloy < 15% Zn piping, piping components, and piping elements exposed to air with borated water leakage (3.2.1
| |
| -57) None None No None Consistent with GALL Report
| |
| *In the RAI response dated June 19, 2012, the applicant changed items 3.2.1
| |
| -10 and 3.3.1
| |
| -3 from "Not Applicable" to "Applicable" and managed these items with Water Chemistry and One
| |
| -Time Inspection Programs.
| |
| The staff's review of the ESF systems' component groups followed several approaches. One approach, documented in SER Section 3.2.2.1, reviewed AMR results for components that the applicant indicated are consistent with the GALL Report and require no further evaluation. Another approach, documented in SER Section 3.2.2.2, reviewed AMR results for components that the applicant indicated are consistent with the GALL Report for which further evaluation is recommended. A third approach, documented in SER Section 3.2.2.3, reviewed AMR results for components that the applicant indicated are not consistent with, or not addressed in, the GALL Report. The staff's review of AMPs credited to manage or monitor aging effects of the ESF system components is documented in SER Section 3.0.3.
| |
| 3.2.2.1 Aging Management Review Results Consistent with the GALL Report LRA Section 3.2.2.1 identifies the materials, environments, AERMs, and the following programs that manage aging effects for the ESF systems' components:
| |
| * ASME Code Section XI ISI Subsections IWB, IWC, and IWD Program
| |
| * Bolting Integrity Program
| |
| * Boric Acid Corrosion Program
| |
| * Closed-Cycle Cooling Water System Program
| |
| * External Surfaces Monitoring Program
| |
| * Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program
| |
| * Lubricating Oil Analysis Program
| |
| * One-Time Inspection Program
| |
| * One-Time Inspection of ASME Code Class 1 Small
| |
| -Bore Piping Program
| |
| * Water Chemistry Program LRA Tables 3.2.2
| |
| -1 through 3.2.2
| |
| -4 summarize AMRs for the ESF system components and indicate AMRs claimed to be consistent with the GALL Report.
| |
| For component groups evaluated in the GALL Report for which the applicant claimed consistency and for which the GALL Report does not recommend further evaluation, the staff Aging Management Review Results 3-332 performed an audit and review to determine if the plant
| |
| -specific components in these GALL Report component groups were bounded by the GALL Report evaluation.
| |
| The applicant provided a note for each AMR item describing how the information in the tables aligns with the information in the GALL Report. The staff reviewed those AMRs with Notes A
| |
| -E, which indicate how the AMR was consistent with the GALL Report.
| |
| Note A indicates that the AMR item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. The staff reviewed these items to verify consistency with the GALL Report and the validity of the AMR for the site
| |
| -specific conditions.
| |
| Note B indicates that the AMR item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff reviewed these items to verify consistency with the GALL Report and to ensure that it had reviewed and accepted the identified exceptions to the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant was consistent with the AMP identified in the GALL Report and whether the AMR was valid for the site-specific conditions.
| |
| Note C indicates that the component for the AMR item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the AMP identified by the GALL Report. This note indicates that the applicant was unable to find a listing of some system components in the GALL Report; however, the applicant identified a different component in the GALL Report that had the same material, environment, aging effect, and AMP as the component under review. The staff reviewed these items to verify consistency with the GALL Report. The staff also determined whether the AMR item of the different component applied to the component under review and whether the AMR was valid for the site
| |
| -specific conditions.
| |
| Note D indicates that the component for the AMR item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff reviewed these items to verify consistency with the GALL Report. The staff confirmed whether the AMR item of the different component was applicable to the component under review and whether the exceptions to the GALL Report AMPs was reviewed and accepted by the staff. The staff also determined whether the AMP identified by the applicant was consistent with the AMP identified in the GALL Report and whether the AMR was valid for the site
| |
| -specific conditions.
| |
| Note E indicates that the AMR item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited. The staff reviewed these items to verify consistency with the GALL Report and determined whether the identified AMP would manage the aging effect consistent with the AMP identified in the GALL Report and whether the AMR was valid for the site
| |
| -specific conditions.
| |
| The staff reviewed the information in the LRA. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The staff's evaluation follows.
| |
| | |
| Aging Management Review Results 3-333 LRA Table 3.2.1, item 3.2.1
| |
| -48, addresses stainless steel or stainless steel clad steel piping, piping components, piping elements, and tanks exposed to treated borated water greater than 140 °F (60 °C), which are being managed for cracking due to SCC. In addition, the staff noted that the applicant also applied item 3.2.1
| |
| -48 to heat exchanger components, in addressing the management of cracking due to SSC. The LRA credits the Water Chemistry Program to manage the aging effect associated with cracking due to SSC. The GALL Report recommends GALL Report AMP XI.M2, "Water Chemistry" to ensure that these aging effects are adequately managed. The associated AMR items cite generic Note A.
| |
| In its review of components associated with item 3.2.1
| |
| -48, for which the applicant cited generic Note A, the staff noted that it was unclear if any of these components is a Class 1 valve. The staff noted that GALL Report, item IV.C2
| |
| -3, recommends both Water Chemistry Program and a plant-specific program to manage cracking of CASS Class 1 piping, piping components, and piping elements, which have carbon content greater than 0.035 percent or ferrite content less than 7.5 percent, based on the material susceptibility criteria described in NUREG
| |
| -0313, Revision 2. The staff also noted that the recommendations of GALL Report item IV.C2
| |
| -3 may be applicable for the CASS valve bodies exposed to treated borated water greater than 140 °F (60 °C) in LRA Tables 3.1.2
| |
| -1, 3.2.2-3, and 3.3.2
| |
| -3. By letter dated January 5, 2011, the staff issued RAI 3.1.2.1
| |
| -01, requesting that the applicant clarify whether any of the CASS valves in the RCS, RH system, or chemical and volume control system is a Class 1 component, for which the GALL Report recommends a plant
| |
| -specific program, in addition to the Water Chemistry Program, to manage SCC. The staff also requested the applicant to justify why the Water Chemistry Program alone, without a plant
| |
| -specific program, is adequate to manage the cracking due to SCC for the CASS Class 1 component if any of these CASS valves is a Class 1 component that has carbon content greater than 0.035 percent or ferrite content less than 7.5 percent.
| |
| In its response dated February 3, 2011, the applicant stated that the valves associated with the items for CASS valve bodies in the environment of treated borated water greater than 140 °F (60 °C) are not Class 1 components. The applicant further stated that no plant
| |
| -specific program is required in addition to the Water Chemistry Program to manage cracking due to SCC based on the material susceptibility criteria described in NUREG
| |
| -0313, Revision 2. The staff finds the applicant's response unacceptable because the guidance in the SRP
| |
| -LR and GALL Report was revised in License Renewal Interim Staff Guidance (LR
| |
| -ISG), LR-ISG-2011-01, "Aging Management of Stainless Steel Structures and Components in Treated Borated Water," to add the One-Time Inspection Program to verify the effectiveness of the Water Chemistry Program to manage stainless steel components for loss of material, cracking, and reduction of heat transfer in treated borated water environments that are not controlled to low oxygen levels. The staff noted that, prior to issuance of LR
| |
| -ISG-2011-01; the SRP
| |
| -LR and GALL Report guidance inappropriately credited the boron in borated water as a corrosion inhibitor in place of other aging management activities.
| |
| By letter dated May 29, 2012, the staff issued RAI 3.2.1.48
| |
| -1, requesting that the applicant describe how the effectiveness of the Water Chemistry Program to manage cracking due to SCC will be verified for stainless steel components exposed to treated borated water with greater than 5 ppb oxygen. This issue was identified as Open Item OI 3.2.2.1
| |
| -1. In its response dated June 19, 2012, and the correction to this response dated July 20, 2012, the applicant revised the LRA to add the One
| |
| -Time Inspection Program to verify the Aging Management Review Results 3-334 effectiveness of the Water Chemistry Program to manage cracking of stainless steel and CASS components exposed to treated borated water environments with temperatures greater than 140 °F (60 °C). The staff finds the applicant's response acceptable because the effectiveness of the Water Chemistry Program will be verified by the applicant to ensure that potential degradation due to SCC does not lead to loss of intended function during the period of extended operation. In addition, the staff evaluated the adequacy of the applicant's Water Chemistry and One-Time Inspection Programs in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. In its review of components associated with LRA Table 3.2.1, item 3.2.1
| |
| -48, the staff finds the applicant's proposal to manage aging using the Water Chemistry and One
| |
| -Time Inspection Programs acceptable, because the Water Chemistry Program establishes the plant water chemistry control parameters and their limits to mitigate aging and identifies the actions required if the parameters exceed the limits, and the One
| |
| -Time Inspection Program prescribes appropriate visual, surface, or other inspection techniques capable of detecting cracking prior to loss of intended function, consistent with the revised GALL Report guidance in LR
| |
| -ISG-2011-01. Based on its review, 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). The staff's concern regarding cracking of components associated with LRA Table 3.2.1, item 3.2.1
| |
| -48, and described in RAI 3.2.1.48
| |
| -1, is resolved.
| |
| LRA Table 3.2.1, item 3.2.1
| |
| -49 addresses stainless steel piping, piping components, piping elements, tanks, and heat exchanger components exposed to treated borated water which are being managed for loss of material due to pitting and crevice corrosion. The LRA credits the Water Chemistry Program to manage the aging effect. The GALL Report recommends GALL Report AMP XI.M2, "Water Chemistry," to ensure that these aging effects are adequately managed. The associated AMR items cite generic Notes A or C.
| |
| In its review of components associated with item 3.2.1
| |
| -49 for which the applicant cited generic Notes A or C, the staff noted that the guidance in the SRP
| |
| -LR and GALL Report was revised in LR-ISG-2011-01, "Aging Management of Stainless Steel Structures and Components in Treated Borated Water," to add the One
| |
| -Time Inspection Program to verify the effectiveness of the Water Chemistry Program to manage stainless steel components for loss of material, cracking, and reduction of heat transfer in treated borated water environments that are not controlled to low oxygen levels. The staff noted that, prior to the issuance of LR
| |
| -ISG-2011-01, the SRP-LR and GALL Report guidance inappropriately credited the boron in borated water as a corrosion inhibitor in place of other aging management activities.
| |
| By letter dated May 29, 2012, the staff issued RAI 3.2.1.48
| |
| -1, requesting that the applicant describe how the effectiveness of the Water Chemistry Program to manage loss of material will be verified for stainless steel components exposed to treated borated water with greater than 5 ppb oxygen. This issue was identified as Open Item OI 3.2.2.1
| |
| -1. In its response dated June 19, 2012, the applicant revised the LRA to add the One
| |
| -Time Inspection Program to verify the effectiveness of the Water Chemistry Program to manage loss of material for stainless steel components exposed to treated borated water. The staff finds the applicant's response acceptable because the effectiveness of the Water Chemistry Program will be verified by the applicant to ensure that potential degradation due to corrosion does not lead to loss of intended function during the period of extended operation. In addition, the staff evaluated the adequacy of the applicant's Water Chemistry and One
| |
| -Time Inspection Programs Aging Management Review Results 3-335 in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. In its review of components associated with LRA Table 3.2.1, item 3.2.1
| |
| -49, the staff finds the applicant's proposal to manage aging using the Water Chemistry and One
| |
| -Time Inspection Programs acceptable, because the Water Chemistry Program establishes the plant water chemistry control parameters and their limits to mitigate aging and identifies the actions required if the parameters exceed the limits, and the One-Time Inspection Program prescribes appropriate visual, volumetric, or other inspection techniques capable of detecting loss of material prior to loss of intended function, consistent with the revised GALL Report guidance in LR
| |
| -ISG-2011-01. Based on its review, 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). The staff's concern regarding loss of material of components associated with LRA Table 3.2.1, item 3.2.1-49, and described in RAI 3.2.1.48
| |
| -1 is resolved.
| |
| The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing aging effects. On the basis of its review, the staff concludes that the AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed consistent with its AMRs. Therefore, the staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.2.2.1.1 Aging Management Review Results Identified as Not Applicable LRA Table 3.2.1, items 3.2.1
| |
| -18, 3.1.2-19, and 3.2.1
| |
| -20, state that these items are applicable only to BWRs. The staff confirmed that these items do not apply because the unit is a PWR design. Based on this determination, the staff finds that the applicant provided an acceptable basis for concluding AMR items 3.2.1
| |
| -18, 3.1.2-19, and 3.2.1
| |
| -20 are not applicable.
| |
| For LRA Table 3.2.1, items 3.2.1
| |
| -21, 3.2.1-22, 3.2.1-33, 3.2.1-34, 3.2.1-36, 3.2.1-37, 3.2.1-40, 3.2.1-42, 3.2.1-43, 3.2.1-44, and 3.2.1
| |
| -47, the applicant claimed these items were not applicable. The staff reviewed the LRA and UFSAR and confirmed that the applicant's LRA does not have any AMR results that are applicable for these items.
| |
| LRA Table 3.2.1, item 3.2.1-54 addresses steel piping, piping components, and piping elements exposed to controlled indoor air (external) and states that there are no aging effects, aging mechanisms, or AMPs. The GALL Report, Table V, item V.F
| |
| -16 (EP-4) recommends that there is no aging effect or aging mechanism and that no AMP is recommended for this component group exposed to this environment, and, therefore, the staff finds the applicant's determination acceptable.
| |
| LRA Table 3.2.1, item 3.2.1
| |
| -55 addresses steel and stainless steel piping, piping components, and piping elements exposed to concrete and states that there are no aging effects, aging mechanisms, or AMPs. The GALL Report, Table V, items V.F
| |
| -14 (EP-20) and V.F
| |
| -17 (EP-5) recommend that there is no aging effect or aging mechanism and that no AMP is recommended for these component groups exposed to this environment, and, therefore, the staff finds the applicant's determination acceptable.
| |
| | |
| Aging Management Review Results 3-336 3.2.2.1.2 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced Corrosion, and Fouling LRA Table 3.2.1, item 3.2.1
| |
| -35, addresses steel containment isolation piping and components internal surfaces exposed to raw water, which are being managed for loss of material due to general, pitting, crevice, and microbiologically
| |
| -influenced corrosion, and fouling. The applicant credits the Fire Water System Program to manage the aging effect. The GALL Report recommends GALL Report AMP XI.M20, "Open
| |
| -Cycle Cooling Water System," to ensure that these aging effects are adequately managed. The associated AMR items cite generic Note E with plant
| |
| -specific notes that state the raw water environment is associated with the Fire Water System; therefore, the Open
| |
| -Cycle Cooling Water System Program is not applicable.
| |
| GALL Report AMP XI.M20 recommends using condition and performance monitoring programs to manage the aging of these items. In addition, GALL Report AMP XI.M20 recommends using chemical treatments whenever the potential for biological fouling species exists and also recommends the use of periodic flushing. In its review of components associated with LRA Table 3.2.1, item 3.2.1
| |
| -35, for which the applicant cited generic Note E, the staff noted that the Fire Water System Program proposes to manage the aging of steel isolation piping and components internal surfaces through the use of inspections, periodic flushing, system performance testing, and chemical additions to prevent microbiological growth.
| |
| The staff's evaluation of the applicant's Fire Water System Program is documented in SER Section 3.0.3.2.8.
| |
| In its review of components associated with LRA Table 3.2.1, item 3.2.1
| |
| -35, the staff finds the applicant's proposal to manage aging using the Fire Water System Program acceptable because the program conducts inspections roughly every outage and uses preventive actions including chemical additions and performance verification.
| |
| The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.2.2.1.3 Loss of Material Due To Pitting, Crevice, and Microbiologically
| |
| -Influenced Corrosion, and Fouling LRA Table 3.2.1, item 3.2.1
| |
| -38, addresses stainless steel containment isolation piping and components internal surfaces exposed to raw water, which are being managed for loss of material due to pitting, crevice, and microbiologically
| |
| -influenced corrosion, and fouling. The applicant credits the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage the aging effect. The GALL Report recommends GALL Report AMP XI.M20, "Open
| |
| -Cycle Cooling Water System," to ensure that these aging effects are adequately managed. The associated AMR items cite generic Note E with specific notes that state the raw water environment is associated with radioactive liquid waste drainage; therefore, the Open
| |
| -Cycle Cooling Water System Program is not applicable.
| |
| GALL Report AMP XI.M20 recommends using condition and performance monitoring programs to manage the aging of these items. In addition, GALL Report AMP XI.M20 recommends using chemical treatments whenever the potential for biological fouling species exists and also recommends the use of periodic flushing. In its review of components associated with LRA Table 3.2.1, item 3.2.1
| |
| -38, for which the applicant cited generic Note E, the staff noted that the Aging Management Review Results 3-337 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program proposes to manage the aging of stainless steel isolation piping and components' internal surfaces through the use of periodic inspection on the internal surfaces of components. It was not clear to the staff how the opportunistic visual inspections will be able to manage aging of components in a raw water system that does not include chemical treatments or surveillances. By letter dated January 5, 2011, the staff issued RAI 3.3.2.2
| |
| -1, requesting that the applicant justify the use of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Component Program, which is only a visual inspection program to manage aging in the raw water environment.
| |
| In its response dated February 3, 2011, the applicant stated that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program was chosen because the internal raw water environments are not covered by any other AMP. The applicant also stated that its conclusion to use this AMP is supported by information in Revision 2 to the GALL Report, that this program applies to components exposed to any water systems not included in the open-cycle cooling water, closed treated water, or fire water AMPs. The applicant further stated that its equipment inspections have been successful at identifying and resolving corrosion or degradation before it affects the ability of the component to perform its intended function. The staff finds the applicant's response acceptable because the GALL Report, Revision 2, allows for components exposed to raw water, which are not part of the open
| |
| -cycle cooling water, to be managed with the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Component Program; therefore, the applicant's proposal is in accordance with the current staff position. The staff's concern described in RAI 3.3.2.2
| |
| -1 is resolved.
| |
| The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. In its review of components associated with LRA Table 3.2.1, item 3.2.1
| |
| -38, the staff finds the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program acceptable. The program conducts inspections during periodic system surveillances or maintenance activities when internal surfaces are accessible and monitors parameters such as corrosion, corrosion byproducts, coating degradation, scale/deposits, pits, and surface discoloration and discontinuities, which is sufficient to manage aging of these components and is consistent with the staff's current position.
| |
| The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| LRA Table 3.2.1, item 3.2.1
| |
| -39, addresses stainless steel heat exchanger components exposed to raw water, which are being managed for loss of material due to pitting, crevice, and microbiologically-influenced corrosion, and fouling. The applicant credits the Fire Water System Program to manage the aging effect. The GALL Report recommends GALL Report AMP XI.M20, "Open
| |
| -Cycle Cooling Water System," to ensure that these aging effects are adequately managed. The associated AMR items cite generic Note E with plant
| |
| -specific notes that state the raw water environment is associated with the fire protection system; therefore, the Open
| |
| -Cycle Cooling Water System Program is not applicable.
| |
| GALL Report AMP XI.M20 recommends using condition and performance monitoring programs to manage the aging of these items. In addition, GALL Report AMP XI.M20 recommends using Aging Management Review Results 3-338 chemical treatments whenever the potential for biological fouling species exists and also recommends the use of periodic flushing. In its review of components associated with LRA Table 3.2.1, item 3.2.1
| |
| -39, for which the applicant cited generic Note E, the staff noted that the Fire Water System Program proposes to manage the aging of stainless steel heat exchanger components through the use of inspections, periodic flushing, system performance testing, and chemical additions to prevent microbiological growth.
| |
| The staff's evaluation of the applicant's Fire Water System Program is documented in SE R Section 3.0.3.2.8. In its review of components associated with LRA Table 3.2.1, item 3.2.1
| |
| -39, the staff finds the applicant's proposal to manage aging using the Fire Water System Program acceptable because the program conducts inspections roughly every outage and uses preventive actions including chemical additions and performance verification.
| |
| The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.2.2.1.4 Loss of Material LRA Table 3.2.1, item 3.2.1
| |
| -32, addresses steel piping and ducting components and internal surfaces exposed to internal indoor uncontrolled air, which will be managed for loss of material caused by general corrosion. The GALL Report recommends GALL Report AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," to ensure that this aging effect is adequately managed.
| |
| During its review of components associated with item 3.2.1
| |
| -32, for which the applicant cited generic Note A, the staff noted that the LRA credits the Fire Water System Program to manage the aging effects for steel piping and fittings and gray cast iron sprinkler heads and valve bodies. The staff noted that the applicant has selected a different AMP to manage the effects of aging than that recommended by the GALL Report. GALL Report AMP XI.M38 recommends using periodic internal visual inspections to manage the effects of aging.
| |
| The staff's evaluation of the applicant's Fire Water System Program is documented in SER Section 3.0.3.2.8. The Fire Water System Program proposes to manage the effects of aging for steel piping and fittings and gray cast iron sprinkler heads and valve bodies through the use of periodic internal visual inspections. Based on its review of components associated with item 3.2.1-32, for which the applicant cited generic Note A, the staff finds the applicant's proposal to manage the effects of aging using the Fire Water System Program acceptable because the inspections are capable of detecting the loss of material.
| |
| The staff concludes that, for LRA item 3.3.1
| |
| -32, the applicant has demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation as required by 10 CFR 54.21(a)(3).
| |
| 3.2.2.1.5 Loss of Material Due to Pitting and Crevice Corrosion
| |
| | |
| Aging Management Review Results 3-339 LRA Table 3.2
| |
| -1, item 3.2.1
| |
| -49, addresses stainless steel tanks exposed to treated borated water, which will be managed for loss of material. For the AMR item that cites generic Note E, the LRA credits the Aboveground Steel Tanks Program to manage the aging effect for tanks. The GALL Report recommends GALL Report AMP XI.M2, "Water Chemistry," to ensure that this aging effect is adequately managed. GALL Report AMP XI.M2 recommends using monitoring and control of reactor water chemistry based on industry guidelines to manage the effects of aging.
| |
| The staff noted that LRA Table 3.2.2
| |
| -2 includes a line item for these tanks that states that loss of material will also be managed by the Water Chemistry Program. The staff's evaluation of the applicant's Aboveground Steel Tanks Program is documented in SER Section 3.0.3.2.9. Based on its review of components associated with item 3.2.1
| |
| -49, for which the applicant cited generic Note E, the staff finds the applicant's proposal to manage the effects of aging using the Aboveground Steel Tanks Program acceptable because the program is consistent with the guidance provided in LR
| |
| -ISG-2012-02, including periodic inspections capable of detecting a loss of material.
| |
| 3.2.2.1.6 Loss of Material Due to General, Pitting, and Crevice Corrosion In LRA Table 3.2.2
| |
| -2, the applicant stated that stainless steel tanks exposed to soil or concrete will be managed for loss of material by the Aboveground Steel Tanks Program. The AMR item cites generic Note E.
| |
| The staff's evaluation of the applicant's Aboveground Steel Tanks Program is documented in SER Section 3.0.3.2.9. The staff finds the applicant's proposal to manage the effects of aging using the Aboveground Steel Tanks Program acceptable because the program is consistent with the guidance provided in LR
| |
| -ISG-2012-02, including periodic UT examinations capable of detecting the loss of material on the outside surface of the bottom of the tanks.
| |
| 3.2.2.2 Aging Management Review Results Consistent with the GALL Report for Which Further Evaluation is Recommended In LRA Section 3.2.2.2, the applicant further evaluates aging management, as recommended by the GALL Report, for the ESF system components and provides information concerning how it will manage the following aging effects:
| |
| * cumulative fatigue damage
| |
| * loss of material due to cladding breach
| |
| * loss of material due to pitting and crevice corrosion
| |
| * reduction of heat transfer due to fouling
| |
| * hardening and loss of strength due to elastomer degradation
| |
| * loss of material due to erosion
| |
| * loss of material due to general corrosion and fouling
| |
| * loss of material due to general, pitting, and crevice corrosion
| |
| * loss of material due to general, pitting, crevice, and MIC
| |
| * QA for aging management of nonsafety
| |
| -related components For component groups evaluated in the GALL Report, for which the applicant claimed consistency with the report and for which the report recommends further evaluation, the staff Aging Management Review Results 3-340 audited and reviewed the applicant's evaluation to determine if it adequately addressed the issues further evaluated. In addition, the staff reviewed the applicant's further evaluations against the criteria contained in SRP
| |
| -LR Section 3.2.2.2. The staff's review of the applicant's further evaluation follows.
| |
| 3.2.2.2.1 Cumulative Fatigue Damage LRA Section 3.2.2.2.1, which is associated with LRA Table 3.2.1, item 3.2.1
| |
| -1, addresses steel and stainless steel piping, piping components, and piping elements in RH and SI systems exposed to treated water and being managed for cumulative fatigue damage. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that fatigue is a TLAA, as defined in 10 CFR 54.3, and is required to be evaluated in accordance with 10 CFR 54.21(c). The applicant stated that its evaluation of this TLAA is addressed separately in LRA Section 4.3.
| |
| The staff reviewed LRA Section 3.2.2.2.1 against the criteria in SRP
| |
| -LR Section 3.2.2.2.1, which states that cumulative fatigue damage of steel and stainless steel piping, piping components, and piping elements in the ESF systems is a TLAA, and these TLAAs are to be evaluated in accordance with the TLAA acceptance criteria requirements of 10 CFR 54.21(c) and in accordance with SRP
| |
| -LR Section 4.3, "Metal Fatigue Analysis." The staff reviewed the applicant's AMR items and finds that the AMR results are consistent with the recommendations of the GALL Report and SRP
| |
| -LR for managing cumulative fatigue damage in steel and stainless steel piping, piping components, and piping elements exposed to treated water, except as identified below.
| |
| The staff noted that LRA Tables 3.2.2
| |
| -3 and 3.2.2
| |
| -4 do not include any applicable items for management of cumulative fatigue damage in the RH and SI systems. By letter dated January 21, 2010, the staff issued RAI 3.3.2.2.1
| |
| -1, Request 1, asking the applicant to include, in LRA Table 3.2.2
| |
| -3 for RH system and Table 3.2.2
| |
| -4 for SI system, any applicable items related to the management of cumulative fatigue damage in non-Class 1 components or provide the basis for excluding these items from the LRA.
| |
| In its response dated February 18, 2011, the applicant amended LRA Tables 3.2.2
| |
| -3 and 3.2.2-4 to include the associated AMR items for the RH and SI systems, consistent with GALL AMR item V.D1
| |
| -27. The applicant stated that six rows representing TLAAs of stainless steel pressure boundary components such as orifice, piping and fittings, pump casing, thermowell, and valve body exposed to treated borated water have been added to LRA Table 3.2.2-3, and five rows have been added to LRA Table 3.2.2
| |
| -4. Based on its review of the amended LRA Tables 3.2.2
| |
| -3 and 3.2.2
| |
| -4, the staff finds the applicant's response to RAI 3.3.2.2.1
| |
| -1, Request 1, and the additions of the AMR items acceptable because they are consistent with GALL AMR item V.D1
| |
| -27 for the RH and SI systems. The staff's concern described in RAI 3.3.2.2.1
| |
| -1, Request 1, is resolved.
| |
| In its review of LRA Tables 3.2.2
| |
| -3 and 3.2.2
| |
| -4, the staff also noted AMR items associated wit h item 3.1.1
| |
| -8 regarding TLAAs of piping and fittings (Class 1, including less than 4 in.), valve body, and orifice (Class 1). The staff noted that LRA Section 4.3.7 states that the RH and SI system components were designed in accordance with ASME Code Section III, Class 2 and Class 3, requirements. It is not clear to the staff which piping and piping components are represented in these rows in LRA Tables 3.2.2
| |
| -3 and 3.2.2
| |
| -4 and if these components represent the portions of the RH and SI systems that are located inside the reactor containment.
| |
| | |
| Aging Management Review Results 3-341 By letter dated January 21, 2010, the staff issued RAI 3.3.2.2.1
| |
| -2, asking the applicant to clarify which portions of the RH and SI systems are represented by item 3.1.1
| |
| -8 in LRA Tables 3.2.2
| |
| -3 and 3.3.2-4. The staff also requested that the applicant clarify the inconsistency between LRA Section 4.3.7, which states that the RH and SI systems components were designed to ASME Code Section III Class 2 and Class 3 requirements and LRA Table 3.1.1, item 3.1.1
| |
| -8, which represents Class 1 components. Furthermore, the staff requested that the applicant identify the TLAA in LRA Section 4 that represents these AMR items. As part of the RAI 3.3.2.2.1
| |
| -2, the staff also sent similar questions regarding the chemical and volume control system (CVCS). The staff's evaluation of the applicant's response to the portion of the RAI related to the CVCS is documented in SER Section 3.3.2.2.1.
| |
| In its response dated February 18, 2011, the applicant clarified that item 3.1.1
| |
| -8 represents the Class 1 RCPB components in the RH (LRA Table 3.2.2
| |
| -3) and SI (Table 3.2.2
| |
| -4) systems. The applicant also stated that AMR items that represents the Class 2 and Class 3 components in the RH and SI systems were added to LRA Table 3.2.2
| |
| -3 and Tables 3.2.2
| |
| -4, as part of the response in RAI 3.3.2.2
| |
| .1-1. The applicant stated that the Class 1 RCPB components in the RH and SI systems, which are part of the NSSS, are evaluated in LRA Section 4.3.1 and 4.3.2. The applicant also stated that the TLAAs for Class 2 and Class 3 components are evaluated in LRA Section 4.3.7.
| |
| Based on its review, the staff finds the applicant's response to RAI 3.3.2.2.1
| |
| -2 acceptable because the applicant clarified the AMR items and associated TLAAs for Class 1 RCPB components and Class 2 and Class 3 components in the RH and SI systems. The applicant's AMR results are consistent with the recommendations of the GALL Report. The staff's review of the applicant's TLAAs associated with the Classes 1, 2, and 3 components are documented in SER Section 4.3. The staff's concern described in RAI 3.3.2.2.1
| |
| -2 is resolved.
| |
| Based on the staff's review, it concludes that the applicant met the SRP
| |
| -LR Section 3.2.2.2.1 criteria. For those items that apply to LRA Section 3.2.2.2.1, the staff determined that the LRA is consistent with the GALL Report, and the applicant 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). SER Section 4.3 documents the staff's review of the applicant's evaluation of the TLAA for these components.
| |
| 3.2.2.2.2 Loss of Material Due to Cladding Breach LRA Section 3.2.2.2.2, associated with LRA Table 3.2.1, item 3.2.1
| |
| -2, addresses loss of material due to cladding breach in pump casings of steel with stainless steel cladding exposed to treated borated water. The applicant stated that this item is not applicable because the plant's ESF systems do not contain pump casings comprised of steel with stainless steel cladding. The staff reviewed LRA Sections 2.3.2 and 3.2 and the UFSAR and confirmed that no in-scope pump casings of steel with stainless steel cladding exposed to treated borated water are present in the ESF systems; therefore, it finds the applicant's claim acceptable.
| |
| 3.2.2.2.3 Loss of Material Due to Pitting and Crevice Corrosion The staff reviewed LRA Section 3.2.2.2.3 against the following criteria in SRP
| |
| -LR Section 3.2.2.2.3:
| |
| | |
| Aging Management Review Results 3-342 (1) LRA Section 3.2.2.2.3.1, is associated with LRA Table 3.2.1, item 3.2.1
| |
| -3, and addresses stainless steel containment isolation piping, piping components, and piping elements exposed to treated water, which are being managed for loss of material due to pitting and crevice corrosion by the Water Chemistry and One
| |
| -Time Inspection Programs. The criteria in SRP
| |
| -LR Section 3.2.2.2.3, item 1, state that loss of material due to pitting and crevice corrosion could occur for internal surfaces of stainless steel containment isolation piping, piping components, and piping elements exposed to treated water. The SRP
| |
| -LR also states that the Water Chemistry Program relies on monitoring and control of water chemistry to mitigate degradation, and a one
| |
| -time inspection of select components at susceptible locations is an acceptable method to determine if an aging effect does not occur or progresses very slowly such that the component's intended function will be maintained during the period of extended operation. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that loss of material due to pitting and crevice corrosion of stainless steel piping components exposed to treated water will be managed by the Water Chemistry and One-Time Inspection Programs. The applicant stated that, for item 3.2.1
| |
| -3, the applicability is limited to stainless steel containment building spray and demineralized water system components exposed to treated water. The staff noted that a search of LRA Section 3.2 and the applicant's UFSAR confirmed that no in
| |
| -scope piping, piping components, and piping elements exposed to treated water are present in the containment isolation systems, except for those listed in LRA Section 3.2.2.2.3, item 1 and item 3.2.1
| |
| -3. The staff's evaluations of the applicant's Water Chemistry and One
| |
| -Time Inspection Programs are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. In its review of components associated with item 3.2.1
| |
| -3, the staff finds that the applicant met the further evaluation criteria. The staff finds the applicant's proposal to manage aging using the Water Chemistry and One
| |
| -Time Inspection Program acceptable because the Water Chemistry Program uses chemical sampling and corrective actions to ensure that impurities are minimized to reduce aging due to loss of material. Additionally, the One
| |
| -Time Inspection Program will perform visual, surface, volumetric, or other non
| |
| -destructive examination methods of components determined to be most susceptible to degradation to verify the effectiveness of the Water Chemistry Program for managing the aging effects of loss of material.
| |
| Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.2.2.2.3, item 1, criteria. For those items that apply to LRA Section 3.2.2.2.3.1, the staff determined that the LRA is consistent with the GALL Report. The staff also finds that the applicant 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).
| |
| (2) LRA Section 3.2.2.2.3.2, associated with LRA Table 3.2.1, item 3.2.1
| |
| -4, addresses loss of material from pitting and crevice corrosion in stainless steel piping, piping components, and piping elements exposed to a soil environment. The applicant stated that this item is not applicable because there are no stainless steel components in the ESF systems that are exposed to soil. The staff reviewed LRA Sections 2.3.2 and 3.2 Aging Management Review Results 3-343 and the applicant's UFSAR and confirmed that no in
| |
| -scope stainless steel piping, piping components and piping elements exposed to a soil environment are present in the ESF systems; therefore, it finds the applicant's claim acceptable.
| |
| (3) LRA Section 3.2.2.2.3, item 3, associated with LRA Table 3.2.1, item 3.2.1
| |
| -5, addresses loss of material due to pitting and crevice corrosion in BWR stainless steel and aluminum piping, piping components, and piping elements exposed to treated water. The applicant stated that this item is not applicable because it is only applicable to BWRs. The staff reviewed the SRP
| |
| -LR and LRA Section 3.2 and noted that this item is associated only with BWRs; therefore, it finds the applicant's claim acceptable. (4) LRA Section 3.2.2.2.3.4, referenced by LRA Table 3.2.1, item 3.2.1
| |
| -6, addresses stainless steel and copper
| |
| -alloy piping, piping components, and piping elements exposed to lubricating oil, which are being managed for loss of material due to pitting and crevice corrosion by the Lubricating Oil Analysis and One
| |
| -Time Inspection Programs. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that the One
| |
| -Time Inspection Program will be used to verify the effectiveness of the Lubricating Oil Analysis Program to manage loss of material through examination of susceptible locations in stainless steel piping components in the RH and SI systems, copper-alloy piping components and copper
| |
| -alloy heat exchanger components in the SI system, and stainless steel heat exchanger components in the SI system. In addition, the applicant stated that MIC will be managed on the stainless steel piping components exposed to lubricating oil in the RH and SI systems as well as stainless steel heat exchanger components exposed to lubricating oil in the SI system.
| |
| The staff reviewed LRA Section 3.2.2.2.3.4 against the criteria in SRP
| |
| -LR Section 3.2.2.2.3, item 4, which states loss of material from pitting and crevice corrosion could occur for stainless steel and copper
| |
| -alloy piping, piping components, and piping elements exposed to lubricating oil. The SRP
| |
| -LR also states that the existing program relies on the periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion. The SRP
| |
| -LR further states that control of lube oil contaminants may not always have been adequate to preclude corrosion; therefore, the effectiveness of lubricating oil control should be confirmed to ensure that corrosion does not occur. The SRP-LR also states that the GALL Report recommends further evaluation to verify the effectiveness of the Lubricating Oil Program for which a one
| |
| -time inspection of selected components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that the component's intended function will be maintained during the period of extended operation.
| |
| The staff's evaluations of the applicant's Lubricating Oil Analysis and O ne-Time Inspection programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.1.8, respectively. In its review of components associated with item 3.2.1
| |
| -6, the staff finds the applicant's proposal to manage aging using the One
| |
| -Time Inspection Program to verify the effectiveness of the Lubricating Oil Analysis Program acceptable because the Lubricating Oil Analysis Program was determined to be consistent with the GALL Report. Additionally, the applicant stated that the One
| |
| -Time Inspection Program will be used to examine stainless steel piping and copper
| |
| -alloy piping components to verify the effectiveness of the Lubricating Oil Analysis Program. The staff finds that this satisfies the acceptance criteria in SRP
| |
| -LR Section 3.2.2.2.3, item 4; therefore, the applicant's AMR is consistent with the GALL Report.
| |
| | |
| Aging Management Review Results 3-344 Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.2.2.2.3, item 4, criteria. For the items that apply to LRA Section 3.2.2.2.3.4, the staff determined that the LRA is consistent with the GALL Report, and the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| (5) LRA Section 3.2.2.2.3.5, associated with LRA Table 3.2.1, item 3.2.1
| |
| -7, addresses loss of material from pitting and crevice corrosion in partially encased stainless steel tanks exposed to raw water due to cracking of the perimeter seal from weathering. The applicant stated that this item is not applicable because there are no partially encased stainless steel tanks in the ESF systems exposed to raw water. The staff reviewed LRA Sections 2.3.2 and 3.2 and the applicant's UFSAR and confirmed that no in
| |
| -scope partially encased stainless steel tanks exposed to raw water are present in the ESF systems; therefore, it finds the applicant's claim acceptable.
| |
| (6) LRA Section 3.2.2.2.3.6, associated with LRA Table 3.2.1, item 3.2.1
| |
| -8, addresses loss of material due to pitting and crevice corrosion in stainless steel piping, piping components, piping elements, and tanks exposed to condensation (internal). The applicant stated that this item is not applicable because its ESF systems do not contain stainless steel piping, piping components, piping elements, and tanks exposed to condensation (internal). The staff reviewed LRA Sections 2.3.2 and 3.2 and the UFSAR and confirmed that no in
| |
| -scope stainless steel piping, piping components, piping elements, and tanks exposed to condensation (internal) are present in the ESF systems; therefore, it finds the applicant's claim acceptable.
| |
| 3.2.2.2.4 Reduction of Heat Transfer Due to Fouling The staff reviewed LRA Section 3.2.2.2.4 against the following criteria in SRP
| |
| -LR Section 3.2.2.2.4:
| |
| (1) LRA Section 3.2.2.2.4.1, is associated with LRA Table 3.2.1, item 3.2.1
| |
| -9, and addresses steel, stainless steel, and copper heat exchanger tubes exposed to lubricating oil, which are being managed for reduction of heat transfer due to fouling by the Lubricating Oil Analysis and One
| |
| -Time Inspection Programs.
| |
| The criteria in SRP
| |
| -LR Section 3.2.2.2.4, item 1, state that reduction of heat transfer due to fouling may occur in steel, stainless steel, and copper
| |
| -alloy heat exchanger tubes exposed to lubricating oil. The SRP
| |
| -LR also states that the existing AMP controls lube oil chemistry to mitigate this aging effect, and the effectiveness should be confirmed because the lube oil chemistry controls may not be effective in precluding fouling. The SRP-LR further states that a one
| |
| -time inspection of selected components at susceptible locations is an acceptable method to verify the program's effectiveness. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that it will implement the One-Time Inspection Program to verify the effectiveness of the Lubricating Oil Analysis Program to manage loss of heat transfer due to fouling in the chemical and volume control, diesel generator, and SI systems.
| |
| The staff's evaluations of the applicant's Lubricating Oil Analysis and One
| |
| -Time Inspection Programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.1.8, respectively. In its review of components associated with item 3.2.1
| |
| -9, the staff finds Aging Management Review Results 3-345 that the applicant has met the review criteria of the SRP
| |
| -LR with respect to a one
| |
| -time inspection of selected components at susceptible locations, and the applicant's proposal to manage aging using the specified AMPs acceptable because the Lubricating Oil Analysis Program includes periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits. Additionally, the One
| |
| -Time Inspection Program will verify the effectiveness of the Lubricating Oil Analysis Program to manage this aging effect. Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.2.2.2.4, item 1, criteria. For those items that apply to LRA Section 3.2.2.2.4.1, the staff determined that the LRA is consistent with the GALL Report, and the applicant 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).
| |
| (2) LRA Section 3.2.2.2.4.2, is associated with LRA Table 3.2.1, item 3.2.1
| |
| -10, and addresses stainless steel heat exchanger tubes exposed to treated water. The applicant stated that this item is not applicable because there are no stainless steel heat exchanger tubes exposed to treated water in the ESF systems. To verify this, the staff reviewed LRA Section 3.2 and noted that, although there were no in
| |
| -scope stainless steel heat exchanger tubes exposed to treated water in the ESF systems, there were several systems with heat exchanger tubes exposed to treated borated water. Since the related item, EP
| |
| -34, from SRP
| |
| -LR Table 3.2.1, was derived from a previous SER for heat exchanger tubes exposed to treated borated water, the applicant's determination that this item was not applicable did not appear appropriate. By letter dated February 24, 2011, the staff issued RAI 3.2.2.2.4.2
| |
| -1, requesting that the applicant provide additional bases regarding the non
| |
| -applicability of this item and address how the reduction in heat transfer would be managed for heat exchanger tubes identified as having a heat transfer function.
| |
| In its response dated March 22, 2011, the applicant stated that the "treated borated water" environment is different than the "treated water" environment. The applicant provided the definitions of treated water and treated boated water from the GALL Report Section IX.D, which states that, unlike the PWR reactor coolant environment (treated borated water), the BWR reactor coolant environment (treated water) does not contain boron, a recognized corrosion inhibitor. The applicant also referred to GALL Report Section IX.F, which describes fouling as an accumulation of deposits that may be due to biofouling or particulate fouling, such as sediment, silt, or corrosion products. The applicant further stated that none of the heat exchanger tubes in LRA Section 3.2 are exposed to treated water; however, the containment building spray and RH heat exchanger tubes have an internal environment of treated borated water and an external environment of closed
| |
| -cycle cooling water. The applicant also stated that reduction of heat transfer was applied to the tube side exposed to the closed
| |
| -cycle cooling water but not to the tube side exposed to treated borated water, and it provided the following basis:
| |
| * The Seabrook Station's determination that reduction of heat transfer is not an aging effect in treated borated water environment is based on plant and industry operating experience. Seabrook Station is not aware of any fouling in treated borated water environment leading to reduction of heat transfer in stainless steel Aging Management Review Results 3-346 heat exchanger tubes. This conclusion is consistent with NUREG
| |
| -1801 Rev.1. NUREG-1801 Revision 1 does not identify reduction of heat transfer as an aging effect for stainless steel heat exchanger tubes in treated borated water environment.
| |
| * Fouling of the stainless steel heat exchanger tubes on the treated borated water side would only occur through the buildup of corrosion products. Since the Seabrook Station's treated borated water contains boron, a corrosion inhibitor, corrosion product buildup resulting in reduction of heat transfer in treated borated water environment is not a credible aging effect/mechanism. This is further validated by NUREG
| |
| -1801, Revision 1 line items V.A
| |
| -27, and V.D1
| |
| -30 (NUREG-1800, Table 3.2
| |
| -1, items 48 and 49), which state that Water Chemistry Program alone (for PWR primary water) is adequate for managing loss of material in stainless steel components exposed to treated borated water indicating that corrosion is not expected to occur in stainless steel components exposed to treated borated water. In the absence of corrosion, corrosion product buildup will not occur. Additionally, since reduction of heat transfer in treated borated water is not identified as a potential aging effect, no line items for reduction of heat transfer in treated borated water appear in the LRA.
| |
| * Seabrook's conclusion is consistent with NUREG
| |
| -1801 Rev. 1 and Rev. 2, as well as the NRC staff conclusions as stated in Beaver Valley Final SER (Section 3.2.2.3.2) and Prairie Island SER (Section 3.2.2.2.4).
| |
| The staff reviewed the applicant's response and the cited portions of the GALL Report. The staff noted that, although the GALL Report, Revision 1, states that boron is a recognized corrosion inhibitor, the GALL Report, Revision 2, deleted that discussion from the definition of treated water. The staff also reviewed AMR items V.A
| |
| -27 and V.D1-30 (SRP-LR, Table 3.2
| |
| -1 item 49) and noted that the GALL Report credits Water Chemistry to manage loss of material due to pitting and crevice corrosion in stainless components exposed to treated borated water. The staff also noted that, although the basis for adding these items in the GALL Report, Revision 1, stated that a significant loss of material was not expected, the potential for corrosion and consequently corrosion product buildup still exists. The staff also reviewed the Beaver Valley and Prairie Island SERs and the associated LRAs cited by the applicant and noted that both LRAs identified reduction of heat transfer for stainless steel heat exchanger tubes in a treated borated water environment as an aging effect requiring managing. Based on the above, by letter dated May 23, 2011, the staff issued RAI 3.2.2.2.4.2
| |
| -1A, requesting the applicant to provide its justification to demonstrate that heat exchanger tubes which have a heat transfer intended function do not need to include a reduction of heat transfer aging effect requiring management. In addition, the RAI requested that the applicant provide the plant
| |
| -specific and industry operating experience cited in its previous response demonstrating that reduction in heat transfer was not a credible aging effect for the components in question.
| |
| In its response dated June 2, 2011, the applicant revised LRA Tables 3.2.2
| |
| -2, 3.2.2-3, and 3.3.2-3 to include AMR items for stainless steel heat exchanger components exposed to treated borated water that are being managed for reduction of heat transfer by the Water Chemistry Program. The AMR items cite generic Note H and plant
| |
| -specific Aging Management Review Results 3-347 Note 4, which states that reduction of heat transfer due to fouling is not in the GALL Report for this component, material and environment combination. The staff did not find the applicant's response acceptable because the guidance in the SRP
| |
| -LR and GALL Report was revised in LR
| |
| -ISG-2011-01, "Aging Management of Stainless Steel Structures and Components in Treated Borated Water," to add the One
| |
| -Time Inspection Program to verify the effectiveness of the Water Chemistry Program to manage stainless steel components for loss of material, cracking, and reduction of heat transfer in treated borated water environments that are not controlled to low oxygen levels. The staff noted that, prior to the issuance of LR
| |
| -ISG-2011-01, the SRP
| |
| -LR and GALL Report guidance inappropriately credited the boron in borated water as a corrosion inhibitor in place of other aging management activities.
| |
| Therefore, by letter dated May 29, 2012, the staff issued RAI 3.2.1.48
| |
| -1, requesting that the applicant describe how the effectiveness of the Water Chemistry Program to manage reduction of heat transfer will be verified for stainless steel components exposed to treated borated water with greater than 5 ppb oxygen. This issue was identified as Open Item OI 3.2.2.1
| |
| -1. In its response dated June 19, 2012, the applicant revised the LRA to add reduction of heat transfer as an aging effect for several stainless steel heat exchangers exposed to treated borated water and to manage this aging effect with the Water Chemistry and One-Time Inspection Programs. The applicant also revised LRA Table 3.2.1, item 3.2.1
| |
| -10, to state that this item is now applicable to Seabrook. The staff finds the applicant's response acceptable because the effectiveness of the Water Chemistry Program will be verified by the applicant to ensure that potential fouling does not lead to loss of intended function during the period of extended operation. In addition, the staff evaluated the adequacy of the applicant's Water Chemistry and One
| |
| -Time Inspection Programs, documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. In its review of components associated with item 3.2.1
| |
| -10, the staff finds the applicant's proposal to manage aging using the Water Chemistry and One
| |
| -Time Inspection Programs acceptable, because the Water Chemistry Program establishes the plant water chemistry control parameters and their limits to mitigate aging and identifies the actions required if the parameters exceed the limits, and the One
| |
| -Time Inspection Program prescribes appropriate visual or other inspection techniques capable of detecting fouling prior to loss of intended function, consistent with the revised GALL Report guidance in LR-ISG-2011-01. Based on its review, 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). The staff's concern regarding reduction of heat transfer of heat exchanger tubes in auxiliary systems and described in RAI 3.2.1.48
| |
| -1 is resolved.
| |
| 3.2.2.2.5 Hardening and Loss of Strength Due to Elastomer Degradation LRA Section 3.2.2.2.5 is associated with LRA Table 3.2.1, item 3.2.1
| |
| -11, and addresses hardening and loss of strength due to elastomer degradation. The applicant states that this aging effect is not applicable to Seabrook because this item is applicable to BWRs only.
| |
| SRP-LR Section 3.2.2.2.5 states that hardening and loss of strength due to elastomer degradation could occur in elastomer seals and components associated with the BWR standby Aging Management Review Results 3-348 gas treatment system ductwork and filters exposed to uncontrolled indoor air. The staff finds that SRP-LR Section 3.2.2.2.5 is not applicable because Seabrook is a PWR, and the staff guidance in this SRP
| |
| -LR section is only applicable to BWRs.
| |
| 3.2.2.2.6 Loss of Material Due to Erosion LRA Section 3.2.2.2.6 is associated with LRA Table 3.2.1, item 3.2.1
| |
| -12, and addresses the stainless steel high pressure pump minimum flow orifices in the CVCS exposed to treated borated water, which the applicant proposed to manage for loss of material due to erosion with the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The criterion in SRP
| |
| -LR Section 3.2.2.2.6 states that loss of material due to erosion could occur in high-pressure safety injection (HPSI) pump minimum flow orifices exposed to treated borated water. The SRP
| |
| -LR also states that a plant
| |
| -specific AMP should be evaluated for erosion of the orifice due to extended use of the centrifugal HPSI pump for normal charging. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is adequate to manage the aging effect in these components.
| |
| In its review of components associated with LRA Table 3.2.1, item 3.2.1
| |
| -12, the staff noted that the only components associated with this item are the minimum flow orifices downstream of the two centrifugal charging and high
| |
| -head injection pumps in the CVCS. The staff also noted that the applicant proposed to manage the aging effect for these components through the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The staff further noted that this program consists of inspections of opportunity, performed during pre
| |
| -planned periodic system and component surveillances or during maintenance activities, when the systems are opened and the surfaces are made accessible for visual inspection. Based on the CVCS piping configuration and the limited number of charging pump minimum flow orifices, it was not clear to the staff if opportunities for inspection of these components occur routinely, in accordance with scheduled preventive maintenance or periodic surveillance, or if opportunities for inspection are normally available only during corrective maintenance after degradation or failure of the component may have occurred.
| |
| By letter dated January 5, 2011, the staff issued RAI 3.2.2.2.6
| |
| -01, requesting the applicant to explain whether opportunities for inspection of the charging pump bypass orifices are routinely available. The staff also asked the applicant to justify how the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program will be capable of detecting degradation in these components before failure of their intended function if routine opportunities for inspection are not available.
| |
| In its response dated February 3, 2011, the applicant stated that the CVCS high
| |
| -pressure pump minimum flow orifices are welded in place and are not routinely available for internal visual inspection. The applicant further stated that the minimum flow orifices have multiple internal plates with multiple orifice holes and that these design features of the minimum flow orifices make volumetric examination for dimensional comparison impractical. The applicant proposed to manage loss of material due to erosion in minimum flow orifices with the Water Chemistry Program. The applicant also stated that its TS require quarterly inservice testing of the CVCS high-pressure pumps and that this testing can provide early indication of orifice degradation. The applicant revised LRA Table 3.3.2
| |
| -3, LRA Section 3.2.2.2.6, and LRA Table 3.2.1, item 3.2.1-12, to state that the Water Chemistry Program, rather than the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, will be used to manage Aging Management Review Results 3-349 loss of material due to erosion in CVCS stainless steel orifices exposed to treated borated water. The staff's evaluation of the applicant's Water Chemistry Program is documented in SER Section 3.0.3.1.2. The staff noted that the applicant's Water Chemistry Program is consistent with GALL Report AMP XI.M2, "Water Chemistry." The staff also noted that the GALL Report credits the Water Chemistry Program with providing management for loss of material due to corrosion in stainless steel components exposed to a treated borated water environment; however, the GALL Report does not credit the Water Chemistry Program with managing loss of material due to erosion. The staff further noted that the applicant had neither proposed nor committed to any activity that would confirm effectiveness of the Water Chemistry Program to mitigate erosion in the stainless steel CVCS high-pressure pump minimum flow orifice.
| |
| By letter dated March 7, 2011, the staff issued RAI 3.2.2.2.6
| |
| -02, asking the applicant to include in the AMP(s) for these components an inspection or testing activity to confirm effectiveness of the Water Chemistry Program to mitigate or prevent unacceptable loss of material due to erosion in the stainless steel CVCS high
| |
| -pressure pump minimum flow orifices.
| |
| In its response dated April 5, 2011, the applicant stated that it will credit its high
| |
| -pressure SI pump (CVCS charging pump) TS Performance Monitoring Program to detect loss of material due to erosion in the minimum flow orifices and to confirm effectiveness of the Water Chemistry Program for this component. The applicant stated the following:
| |
| * Its TS require quarterly testing of the CVCS charging pump.
| |
| * The pump is always tested in the same lineup where the flow path is only through the minimum flow orifice.
| |
| * Pump flow and differential pressure are measured, recorded, and compared with acceptance criteria.
| |
| * If the minimum flow orifice should experience erosion to the extent that the acceptance criteria are not met, then restoration of the pump to operable status requires appropriate corrective actions per the corrective action program.
| |
| The applicant revised the LRA by adding a plant
| |
| -specific note in LRA Table 3.3.2
| |
| -3, revising LRA Section 3.2.2.2.6, and adding a new commitment (Commitment 63) to LRA Section A.3. These changes in the LRA state that the TS Performance Monitoring Program for the high
| |
| -pressure safety injection pump (CVCS charging pump) is credited to detect loss of material due to erosion in the minimum flow orifices and provide a commitment to ensure that the quarterly CVCS charging pump testing is continued during the period of extended operation. Appropriate procedures are revised to add a caution stating that an increase in CVCS charging pump minimum flow may be indicative of erosion in the minimum flow orifice.
| |
| The staff noted that SRP
| |
| -LR Appendix A, Section A.1.1, states that a Performance Monitoring Program, which tests the ability of a structure or component to perform its intended function, is an acceptable method for aging management. The staff also noted that the applicant will use its existing quarterly TS Performance Monitoring Program for the CVCS high
| |
| -pressure SI pump (charging pump) to confirm effectiveness of the Water Chemistry Program in mitigating or preventing unacceptable loss of material due to erosion in the stainless steel minimum flow orifices exposed to treated borated water. The staff further noted that the applicant added a Aging Management Review Results 3-350 new commitment (Commitment 63) to ensure that quarterly CVCS charging pump testing is continued during the period of extended operation.
| |
| The staff finds that the applicant has met the further evaluation criteria and that the applicant's proposal to manage aging using the Water Chemistry Program and performance monitoring of the CVCS charging pump is acceptable for the following reasons:
| |
| * Properly maintained water chemistry will mitigate erosion in the CVCS charging pump minimum flow orifice.
| |
| * Performance monitoring will be used to ensure effectiveness of the Water Chemistry Program for this component.
| |
| * Performance monitoring is one of the four general types of AMPs recommended in SRP
| |
| -LR, Appendix A.
| |
| By letter dated January 16, 2016, the applicant modified LRA Appendix A.3, "License Renewal Commitment List," to show the UFSAR location for Commitment 63 as A.2.1.2.
| |
| Based on its review above, the staff finds the applicant's responses to RAIs 3.2.2.2.6
| |
| -01 and 3.2.2.2.6-02 acceptable, and the staff's concerns described in these RAIs are resolved.
| |
| Based on the program identified, and the applicant's commitment to monitor performance, the staff concludes that the applicant's program meets SRP
| |
| -LR Section 3.2.2.2.6 criteria. For those items that apply to LRA Section 3.2.2.2.6, the staff determined that the LRA is consistent with the GALL Report, and the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.2.2.2.7 Loss of Material Due to General Corrosion and Fouling LRA Section 3.2.2.2.7, associated with LRA Table 3.2.1, item 3.2.1
| |
| -13, addresses loss of material due to general corrosion and fouling in steel drywell and suppression chamber spray system nozzle and flow orifice exposed to air
| |
| -indoor uncontrolled (internal). The applicant stated that this item is not applicable because it is only applicable to BWRs. The staff reviewed SRP and LRA Section 3.2 and noted that this item is associated only with BWRs; therefore, it finds the applicant's claim acceptable.
| |
| 3.2.2.2.8 Loss of Material Due to General, Pitting, and Crevice Corrosion The staff reviewed LRA Section 3.2.2.2.8 against the following criteria in SRP
| |
| -LR Section 3.2.2.2.8:
| |
| (1) LRA Section 3.2.2.2.8.1, associated with LRA Table 3.2.1, item 3.2.1
| |
| -14, addresses loss of material due to general, pitting, and crevice corrosion in BWR steel piping, piping components, and piping elements exposed to treated water. The applicant stated that this item is not applicable because it is only applicable to BWRs. The staff reviewed the SRP-LR and LRA Section 3.2 and noted that this item is associated only with BWRs; therefore, it finds the applicant's claim acceptable.
| |
| (2) LRA Section 3.2.2.2.8.2, associated with LRA Table 3.2.1, item 3.2.1
| |
| -15, addresses loss of material due to general, pitting, and crevice corrosion in internal surfaces of steel Aging Management Review Results 3-351 containment isolation piping, piping components, and piping elements exposed to treated water. The applicant stated that this item is not applicable because its ESF systems do not contain steel containment isolation piping, piping components, and piping elements exposed to treated water. The staff reviewed LRA Sections 2.3.2 and 3.2 and the UFSAR and confirmed that no in
| |
| -scope steel containment isolation piping, piping components, and piping elements exposed to treated water are present in the ESF systems; therefore, it finds the applicant's claim acceptable.
| |
| (3) LRA Section 3.2.2.2.8.3, referenced by LRA Table 3.2.1, item 3.2.1
| |
| -16, addresses steel piping, piping components, and piping elements exposed to lubricating oil, which are being managed for loss of material due to general, pitting, and crevice corrosion by the Lubricating Oil Analysis and One
| |
| -Time Inspection Programs. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that the One
| |
| -Time Inspection Program will be used to verify the effectiveness of the Lubricating Oil Analysis Program to manage loss of material due to general, pitting, and crevice corrosion through examination of susceptible locations in steel piping components in the RH and SI systems. In addition, the applicant stated that the One
| |
| -Time Inspection Program will also be used to verify the effectiveness of the Lubricating Oil Analysis Program to manage loss of material due to general, pitting, and crevice corrosion through examination of susceptible locations in steel tanks in the SI system.
| |
| The staff reviewed LRA Section 3.2.2.2.8.3 against the criteria in SRP-LR Section 3.2.2.2.8, item 3, which states that loss of material due to general, pitting, and crevice corrosion could occur for steel piping, piping components, and piping elements exposed to lubricating oil. The SRP
| |
| -LR also states that the existing AMP relies on periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion. The SRP-LR further states that control of lube oil contaminants may not always have been adequate to preclude corrosion; therefore, the effectiveness of lubricating oil control should be confirmed to ensure that corrosion does not occur. The SRP
| |
| -LR also states that the GALL Report recommends further evaluation of programs to verify the effectiveness of the Lubricating Oil Program for which a one
| |
| -time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that the component's intended function will be maintained during the period of extended operation.
| |
| The staff's evaluations of the applicant's Lubricating Oil Analysis and One
| |
| -Time Inspection Programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.1.8, respectively. In its review of components associated with item 3.2.1
| |
| -16, the staff finds the applicant's proposal to manage aging using the One
| |
| -Time Inspection Program to verify the effectiveness of the Lubricating Oil Analysis Program acceptable because the Lubricating Oil Analysis Program was determined to be consistent with the GALL Report. Additionally, the applicant stated that the One
| |
| -Time Inspection Program will be used to examine steel piping, piping components, and piping elements to verify the effectiveness of the Lubricating Oil Analysis Program. This satisfies the acceptance criteria in SRP
| |
| -LR Section 3.2.2.2.8, item 3; therefore, the applicant's AMR is consistent with the GALL Report.
| |
| | |
| Aging Management Review Results 3-352 Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.2.2.2.8, item 3, criteria. For the line items that apply to LRA Section 3.2.2.2.8.3, the staff determined that the LRA is consistent with the GALL Report, and the applicant demonstrated that the effect of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.2.2.2.9 Loss of Material Due to General, Pitting, Crevice, and Microbiologically
| |
| -Influenced Corrosion LRA Section 3.2.2.2.9 is associated with LRA Table 3.2.1, item 3.2.1
| |
| -17, and addresses loss of material due to general, pitting, crevice and MIC in steel (with or without coating or wrapping) piping, piping components, and piping elements exposed to a soil environment. The applicant stated that this item is not applicable because there are no steel (with or without coating or wrapping) piping, piping components, and piping elements in the ESF systems exposed to soil. The staff reviewed LRA Sections 2.3 and 3.2 and the applicant's UFSAR and confirmed that no in-scope steel piping, piping components, and piping elements exposed to a soil environment are present in the ESF systems; therefore, it finds the applicant's determination acceptable.
| |
| 3.2.2.2.10 Quality Assurance for Aging Management of Nonsafety
| |
| -Related Components SER Section 3.0.4 documents the staff's evaluation of the applicant's QA Program.
| |
| 3.2.2.3 Aging Management Review Results Not Consistent with or Not Addressed in the GALL Report In LRA Tables 3.2.2
| |
| -1 through 3.2.2
| |
| -4, the staff reviewed additional details of the AMR results for material, environment, AERM, and AMP combinations not consistent with or not addressed in the GALL Report.
| |
| In LRA Tables 3.2.2
| |
| -1 through 3.2.2
| |
| -4, via Notes F
| |
| -J, the applicant indicated which combinations of component type, material, environment, and AERM do not correspond to an item in the GALL Report. The applicant provided further information about how it will manage the aging effects. Specifically, Note F indicates that the material for the AMR item component is not evaluated in the GALL Report. Note G indicates that the environment for the AMR item component and material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR item component, material, and environment combination is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the item component, material, and environment combination is not applicable. Note J indicates that neither the component nor the material and environment combination for the item is evaluated in the GALL Report.
| |
| For component type, material, and environment combinations not evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine if the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. The staff's evaluation is documented in the following sections.
| |
| 3.2.2.3.1 Combustible Gas Control System
| |
| -Summary of Aging Management Review
| |
| -LRA Table 3.2.2
| |
| -1 Aging Management Review Results 3-353 In LRA Tables 3.2.2
| |
| -1, 3.2.2-2, 3.2.2-3, and 3.3.2
| |
| -4, the applicant stated that the stainless steel bolting exposed to air
| |
| -indoor is being managed for loss of preload by the Bolting Integrity Program. The AMR item cites generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination. Even though stainless steel bolting exposed to air
| |
| -indoor is not specifically addressed in the GALL Report, Table IX.E, the GALL Report states that loss of preload can occur independent of environmental conditions because it can be caused by thermal or mechanical effects. Additionally, Table IX.C of the GALL Report states that stainless steel material is susceptible to a variety of aging effects and mechanisms, including loss of material due to pitting and crevice corrosion and cracking due to SCC. The staff noted that the environment of interest, air
| |
| -indoor, would not induce SCC or loss of material in stainless steel material because stainless steel is inherently resistant to corrosion in the air
| |
| -indoor environment. Therefore, the aging effect of concern is loss of preload, which is addressed in the AMR.
| |
| The staff's evaluation of the applicant's Bolting Integrity Program is documented in SER Section 3.0.3.1.7. While there is no AMR for loss of material of stainless steel bolting exposed to air
| |
| -indoor in the ESF system exposed to indoor air, the GALL Report has items for other material bolting exposed to air
| |
| -indoor managed by the Bolting Integrity Program. The staff finds the applicant's proposal to manage aging using the Bolting Integrity Program acceptable because the Bolting Integrity Program conducts bolting assembly and maintenance control such as application of appropriate gasket alignment, torque, lubricants, and preload. It also inspects for leakage and loose or missing nuts, which verify that the aging effect, loss of preload, will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation.
| |
| In LRA Tables 3.2.2
| |
| -1, 3.2.2-3, and 3.2.2
| |
| -4, the applicant stated that for glass piping elements exposed to air
| |
| -with borated water leakage (external), there is no aging effect, and no AMP is proposed. The AMR item cites generic Note G. The staff reviewed the associated items in the LRA and confirmed that no aging effect is applicable for this component, material, and environment combination because the GALL Report, item V.F
| |
| -9 states that for an environment of treated borated water, there is no AERM and no recommended AMP, and the air with borated water leakage environment is no more severe than the treated borated water environment.
| |
| On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM and AMP combinations not addressed in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.2.2.3.2 Containment Building Spray System
| |
| -Summary of Aging Management Review
| |
| - LRA Table 3.2.2
| |
| -2 The staff's evaluation for stainless steel bolting, exposed to air
| |
| -indoor and being managed for loss of preload by the Bolting Integrity Program citing generic Note G, is documented in SER Section 3.2.2.3.1.
| |
| | |
| Aging Management Review Results 3-354 In LRA Table 3.2.2
| |
| -2, the applicant stated that elastomer flexible hoses exposed to air with borated water leakage (external) are being managed for hardening and loss of strength by the External Surfaces Monitoring Program. The AMR item cites generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination because the GALL Report, Table IX.C, indicates that elastomers are susceptible to hardening and loss of strength at temperatures over 95 °F (35 °C), which is addressed in the AMR item. The GALL Report, item VII.A3
| |
| -1, also indicates that elastomers are susceptible to hardening when exposed to treated borated water.
| |
| The staff's evaluation of the applicant's External Surfaces Monitoring Program is documented in SER Section 3.0.3.2.14. The staff noted that the program includes non
| |
| -visual tactile examinations, such as scratching, which will determine if scale or residues are present or determine if there is a breakdown of material. The staff also noted that the program includes bending and folding of the elastomer to detect cracking that initiates at the surface. The staff further noted that the program includes stretching and pressing to determine the resistance of the material to hardening effects and pressing to gauge the materials resiliency to maintain its strength. The staff finds the applicant's proposal to manage aging using the External Surfaces Monitoring Program acceptable because the program includes periodic visual inspections as well as non
| |
| -visual tactile examinations, which are capable of detecting hardening and loss of strength by detecting discontinuities and imperfections on the surface of the component.
| |
| In LRA Table 3.2.2
| |
| -2, the applicant stated that the stainless steel piping and fittings exposed to air-outdoor (external) are being managed for loss of material by the External Surfaces Monitoring Program. The AMR item cites generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination because the GALL Report, Table IX.C, states that stainless steels are susceptible to loss of material due to pitting and crevice corrosion and cracking due to SCC. The staff noted that the environment of interest, air
| |
| -outdoor (external), would be expected to contain higher levels of chlorides due to the site's relative proximity to the ocean, which is known to induce SCC. By letter dated February 24, 2011 (ADAMS Accession No. ML110260266), the staff issued RAI 3.3
| |
| -1, requesting that the applicant explain why atmospheric chloride
| |
| -induced SCC is not considered to be an applicable aging effect for stainless steel components exposed to outdoor
| |
| -air and explain how SCC will be managed if it is determined to be an applicable aging affect.
| |
| In its response dated March 22, 2011 (ADAMS Accession No. ML110830045), the applicant stated that SCC has been added as an aging mechanism for stainless steel components exposed to air
| |
| -outdoor environment. The applicant added a new item to manage cracking by the External Surfaces Monitoring Program. The staff finds the applicant's response acceptable because the applicant has modified the LRA to include SCC as an applicable aging effect for stainless steel components exposed to outdoor
| |
| -air and include SCC as an aging effect to be managed by the External Surfaces Monitoring Program, which includes visual inspection that is a capable technique to detect SCC. The staff's concern described in RAI 3.3
| |
| -1 is resolved.
| |
| The staff's evaluation of the applicant's External Surfaces Monitoring Program is documented in SER Section 3.0.3.2.14. The staff finds the applicant's proposal to manage aging using the External Surfaces Monitoring Program acceptable because the program uses periodic visual Aging Management Review Results 3-355 inspections that would detect loss of material and detect SCC prior to loss of component
| |
| -intended function.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.2.2.3.3 Residual Heat Removal System
| |
| -Summary of Aging Management Review
| |
| -LRA Table 3.2.2
| |
| -3 The staff's evaluation for stainless steel bolting, exposed to air
| |
| -indoor and being managed for loss of preload by the Bolting Integrity Program citing generic Note G, is documented in SER Section 3.2.2.3.1. The staff's evaluation for glass piping elements exposed to air
| |
| -with borated water leakage (external) with no AERM and no recommended AMP, citing generic Note G, is documented in Section 3.2.2.3.1.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.2.2.3.4 Safety Injection System
| |
| -Summary of Aging Management Review
| |
| -LRA Table 3.2.2-4 The staff's evaluation for stainless steel bolting, exposed to air
| |
| -indoor and being managed for loss of preload by the Bolting Integrity Program citing generic Note G, is documented in SER Section 3.2.2.3.1.
| |
| The staff's evaluation for glass piping elements exposed to air-with borated water leakage (external) with no AERM and no recommended AMP, citing generic Note G, is documented in Section 3.2.2.3.1.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| | |
| ====3.2.3 Conclusion====
| |
| | |
| The staff concludes that the applicant provided sufficient information to demonstrate that the effects of aging for the ESF systems components, within the scope of license renewal and Aging Management Review Results 3-356 subject to an AMR, will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| | |
| ===3.3 Aging===
| |
| Management of Auxiliary Systems This section of the SER documents the staff's review of the applicant's AMR results for the auxiliary system components and component groups of the following systems:
| |
| * auxiliary boiler
| |
| * boron recovery system
| |
| * chemical and volume control system
| |
| * chlorination system
| |
| * containment air handling system
| |
| * containment air purge system
| |
| * containment enclosure air handling system
| |
| * containment online purge system
| |
| * control building air handling system
| |
| * demineralized water system
| |
| * dewatering system
| |
| * diesel generator
| |
| * diesel generator air handling system
| |
| * emergency feed water pump house air handling system
| |
| * fire protection system
| |
| * fuel handling system
| |
| * fuel oil system
| |
| * fuel storage building air handling system
| |
| * hot water heating system
| |
| * instrument air system
| |
| * leak detection system
| |
| * mechanical seal supply system
| |
| * miscellaneous equipment system
| |
| * nitrogen gas system
| |
| * oil collection for reactor coolant pumps system
| |
| * plant floor drain system
| |
| * potable water system
| |
| * primary auxiliary building air handling system
| |
| * primary component cooling water system
| |
| * radiation monitoring system
| |
| * reactor makeup water system
| |
| * release recovery system
| |
| * resin sluicing system
| |
| * roof drains system
| |
| * sample system
| |
| * screen wash system
| |
| * service water system
| |
| * service water pump house air handling system
| |
| | |
| Aging Management Review Results 3-357
| |
| * spent fuel pool cooling system
| |
| * switchyard
| |
| * valve stem leak
| |
| -off system
| |
| * vent gas system
| |
| * waste gas system
| |
| * waste processing liquid system
| |
| * waste processing liquid drains system
| |
| | |
| ====3.3.1 Summary====
| |
| of Technical Information in the Application LRA Section 3.3 provides AMR results for the auxiliary system components and component groups. LRA Table 3.3.1, "Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of NUREG
| |
| -1801," is a summary comparison of the applicant's AMRs with those evaluated in the GALL Report for the auxiliary system components and component groups. The applicant's AMRs evaluated and incorporated applicable plant
| |
| -specific and industry operating experience in the determination of AERMs. The plant
| |
| -specific evaluation included condition reports and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a review of the GALL Report and operating experience issues identified since the issuance of the GALL Report.
| |
| | |
| ====3.3.2 Staff====
| |
| Evaluation The staff reviewed LRA Section 3.3 to determine if the applicant provided sufficient information to demonstrate that it will adequately manage the effects of aging for the auxiliary systems components within the scope of license renewal and subject to an AMR so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| The staff reviewed AMRs to ensure the applicant's claim that certain AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. SER Section 3.3.2.1 documents the staff's evaluations, and SER Section 3.0.3 documents the staff's evaluations of the AMPs.
| |
| The staff also reviewed AMRs consistent with the GALL Report for which further evaluation is recommended. The staff confirmed that the applicant's further evaluations were consistent with the SRP-LR Section 3.3.2.2 acceptance criteria. SER Section 3.3.2.2 documents the staff's evaluations.
| |
| The staff also conducted a technical review of the remaining AMRs not consistent with, or not addressed in, the GALL Report. The technical review evaluated if the applicant identified all plausible aging effects and if the aging effects listed were appropriate for the material and environment combinations specified. SER Section 3.3.2.3 documents the staff's evaluations.
| |
| For SSCs that the applicant claimed were not applicable or required no aging management, the staff reviewed the AMR items and the plant's operating experience to verify the applicant's claims.
| |
| Aging Management Review Results 3-358 Table 3.1-1 summarizes the staff's evaluation of components, aging effects or mechanisms, and AMPs listed in LRA Section 3.3 and addressed in the GALL Report.
| |
| Table 3.3-1. Staff Evaluation for Auxiliary System Components in the GALL Report Component group (GALL Report Item No.) Aging effect/
| |
| mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Steel cranes
| |
| - structural girders exposed to air
| |
| - indoor uncontrolled (external)
| |
| (3.3.1-1) Cumulative fatigue damage TLAA to be evaluated for structural girders of cranes. See the SRP-LR, Section 4.7 for generic guidance for meeting the requirements of 10 CFR 54.21(c)(1).
| |
| Yes TLAA Consistent with GALL Report (see SER Section 3.3.2.2.1)
| |
| Steel and stainless steel piping, piping components, piping elements, and heat exchanger components exposed to air
| |
| - indoor uncontrolled, treated borated water or treated water (3.3.1-2) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c)
| |
| Yes TLAA Consistent with GALL Report (see SER Section 3.3.2.2.1)
| |
| Stainless steel heat exchanger tubes exposed to treated water (3.3.1-3)* Reduction of heat transfer due to fouling Water Chemistry and One-Time Inspection Yes Water Chemistry and One-Time Inspection Consistent with GALL Report (see SER Sections 3.3.2.2.2 and 3.3.2.3.3)
| |
| Stainless steel piping, piping components, and piping elements exposed to sodium pentaborate solution
| |
| > 140 °F (> 60 °C )
| |
| (3.3.1-4) Cracking due to SCC Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (see SER Section 3.3.2.2.3)
| |
| Stainless steel and stainless clad steel heat exchanger components exposed to treated water > 140 °F (> 60 °C)
| |
| (3.3.1-5) Cracking due to SCC A plant-specific AMP is to be evaluated.
| |
| Yes Not applicable Not applicable to Seabrook (see SER Section 3.3.2.2.3)
| |
| | |
| Aging Management Review Results 3-359 Stainless steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust (3.3.1
| |
| -6) Cracking due to SCC A plant-specific AMP is to be evaluated.
| |
| Yes Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Consistent with GALL Report (see SER Section 3.3.2.2.3)
| |
| Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Stainless steel non-regenerative heat exchanger components exposed to treated borated water > 140 °F (> 60 °C)
| |
| (3.3.1-7) Cracking due to SCC and cyclic loading Water Chemistry and a plant
| |
| -specific verification program-An acceptable verification program is to include temperature and radioactivity monitoring of the shell side water and eddy current testing of tubes.
| |
| Yes Water Chemistry and One-Time Inspectio n Consistent with GALL Report (see SER Section 3.3.2.2.4)
| |
| Stainless steel regenerative heat exchanger components exposed to treated borated water > 140 °F (> 60 °C)
| |
| (3.3.1-8) Cracking due to SCC and cyclic loading Water Chemistry and a plant
| |
| -specific verification program-The AMP is to be augmented by verifying the absence of cracking due to stress corrosion cracking and cyclic loading.
| |
| A plant-specific AMP is to be evaluated.
| |
| Yes Water Chemistry and One-Time Inspection Consistent with GALL Report (see SER Section 3.3.2.2.4)
| |
| Stainless steel high
| |
| - pressure pump casing in PWR CVCS(3.3.1
| |
| -9) Cracking due to SCC and cyclic loading Water Chemistry and a plant
| |
| -specific verification program-The AMP is to be augmented by verifying the absence of cracking due to SCC and cyclic loading. A plant-specific AMP is to be evaluated.
| |
| Yes Water Chemistry and One-Time Inspection Consistent with GALL Report (see SER Section 3.3.2.2.4)
| |
| | |
| Aging Management Review Results 3-360 High-strength steel closure bolting exposed to air with steam or water leakage (3.3.1
| |
| -10) Cracking due to SCC and cyclic loading Bolting Integrity
| |
| - The AMP is to be augmented by appropriate inspection to detect cracking if the bolts are not otherwise replaced during maintenance.
| |
| Yes Not applicable Not applicable to Seabrook (see SER Section 3.3.2.2.4)
| |
| Elastomer seals and components exposed to air
| |
| - indoor uncontrolled (internal/external)
| |
| (3.3.1-11) Hardening and loss of strength due to elastomer degradation A plant-specific AMP is to be evaluated.
| |
| Yes Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components and External Surfaces Monitoring Consistent with GALL Report (see SER Section 3.3.2.2.5)
| |
| Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Elastomer lining exposed to treated water or treated borated water (3.3.1-12) Hardening and loss of strength due to elastomer degradation A plant-specific AMP is to be evaluated.
| |
| Yes Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Consistent with GALL Report (see SER Section 3.3.2.2.5)
| |
| Boral, boron steel spent fuel storage racks neutron
| |
| - absorbing sheets exposed to treated water or treated borated water (3.3.1-13) Reduction of neutron- absorbi ng capacity and loss of material due to general corrosion A plant-specific AMP is to be evaluated. Yes Boral Monitoring Consistent with GALL Report (see SER Section 3.3.2.2.6)
| |
| Steel piping, piping component, and piping elements exposed to lubricating oil (3.3.1
| |
| -14) Loss of material due to general, pitting, and crevice corrosion Lubricating Oil Analysis and One
| |
| - Time Inspection Yes Lubricating Oil Analysis and One-Time Inspection Consistent with GALL Report (see SER Section 3.3.2.2.7)
| |
| Steel reactor coolant pump oil collection system piping, tubing, and valve bodies exposed to lubricating oil (3.3.1
| |
| -15) Loss of material due to general, pitting, and crevice corrosion Lubricating Oil Analysis and One
| |
| - Time Inspection Yes Lubricating Oil Analysis and One-Time Inspection Not applicable to Seabrook (see SER Section 3.3.2.2.7)
| |
| | |
| Aging Management Review Results 3-361 Steel reactor coolant pump oil collection system tank exposed to lubricating oil (3.3.1
| |
| -16) Loss of material due to general, pitting, and crevice corrosion Lubricating Oil Analysis and One
| |
| - Time Inspection to evaluate the thickness of the lower portion of the tank Yes Lubricating Oil Analysis and One-Time Inspection Consistent with GALL Report (see SER Section 3.3.2.2.7)
| |
| Steel piping, piping components, and piping elements exposed to treated water (3.3.1
| |
| -17) Loss of material due to general, pitting, and crevice corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (see SER Section 3.3.2.2.7)
| |
| Stainless steel and steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust (3.3.1
| |
| -18) Loss of material/general (steel only) and pitting and crevice corrosion A plant-specific AMP is to be evaluated.
| |
| Yes Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Consistent with GALL Report (see SER Section 3.3.2.2.7) Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Steel (with or without coating or wrapping) piping, piping components, and piping elements exposed to soil (3.3.1-19) Loss of material due to general, pitting, crevice, and MIC Buried Piping and Tanks Surveillance or Buried Piping and Tanks Inspection No Yes Buried Piping and Tanks Inspection Consistent with GALL Report (see SER Section 3.3.2.2.8)
| |
| Steel piping, piping components, piping elements, and tanks exposed to fuel oil (3.3.1-20) Loss of material due to general, pitting, crevice, and MIC, and fouling Fuel Oil Chemistry and One-Time Inspection Yes Fuel Oil Chemistry and One-Time Inspection, and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Consistent with GALL Report (see SER Section 3.3.2.2.9)
| |
| Steel heat exchanger components exposed to lubricating oil (3.3.1
| |
| -21) Loss of material due to general, pitting, crevice, and MIC, and fouling Lubricating Oil Analysis and One
| |
| - Time Inspection Yes Lubricating Oil Analysis and One-Time Inspection Consistent with GALL Report (see SER Section 3.3.2.2.9)
| |
| | |
| Aging Management Review Results 3-362 Steel with elastomer lining or stainless steel cladding piping, piping components, and piping elements exposed to treated water and treated borated water (3.3.1-22) Loss of material due to pitting and crevice corrosion (only for steel after lining/cladding degradation)
| |
| Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to Seabrook (see SER Section 3.3.2.2.10)
| |
| Stainless steel and steel with stainless steel cladding heat exchanger components exposed to treated water (3.3.1
| |
| -23) Loss of material due to pitting and crevice corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (see SER Section 3.3.2.2.10)
| |
| Stainless steel and aluminum piping, piping components, and piping elements exposed to treated water (3.3.1
| |
| -24) Loss of material due to pitting and crevice corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to Seabrook (see SER Section 3.3.2.2.10)
| |
| Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Copper-alloy heating, ventilation, and air conditioning (HVAC) piping, piping components, and piping elements exposed to condensation (external)
| |
| (3.3.1-25) Loss of material due to pitting and crevice corrosion A plant-specific AMP is to be evaluated.
| |
| Yes Bolting Integrity, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components, or External Surfaces Monitoring Consistent with GALL Report (see SER Section 3.3.2.2.10)
| |
| Copper-alloy piping, piping components, and piping elements exposed to lubricating oil (3.3.1
| |
| -26) Loss of material due to pitting and crevice corrosion Lubricating Oil Analysis and One
| |
| - Time Inspection Yes Lubricating Oil Analysis and One-Time Inspection Consistent with GALL Report (see SER Section 3.3.2.2.10)
| |
| | |
| Aging Management Review Results 3-363 Stainless steel HVAC ducting and aluminum HVAC piping, piping components, and piping elements exposed to condensation (3.3.1-27) Loss of material due to pitting and crevice corrosion A plant-specific AMP is to be evaluated.
| |
| Yes Bolting Integrity, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components, External Surfaces Monitoring, Compressed Air Monitoring, and Fire Water System Consistent with GALL Report (see SER Section 3.3.2.2.10)
| |
| Copper-alloy fire protection piping, piping components, and piping elements exposed to condensation (internal)
| |
| (3.3.1-28) Loss of material due to pitting and crevice corrosion A plant-specific AMP is to be evaluated.
| |
| Yes Fire Water Program Consistent with GALL Report (see SER Section 3.3.2.2.10)
| |
| Stainless steel piping, piping components, and piping elements exposed to soil (3.3.1-29) Loss of material due to pitting and crevice corrosion A plant-specific AMP is to be evaluated.
| |
| Yes Buried Piping and Tanks Inspection Consistent with GALL Report (see SER Section 3.3.2.2.10)
| |
| Stainless steel piping, piping components, and piping elements exposed to sodium pentaborate solution (3.3.1-30) Loss of material due to pitting and crevice corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (see SER Section 3.3.2.2.10)
| |
| Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Copper-alloy piping, piping components, and piping elements exposed to treated water (3.3.1-31) Loss of material due to pitting, crevice, and galvanic corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (see SER Section 3.3.2.2.11)
| |
| | |
| Aging Management Review Results 3-364 Stainless steel, aluminum and copper-alloy piping, piping components, and piping elements exposed to fuel oil (3.3.1-32) Loss of material due to pitting, crevice, and MIC Fuel Oil Chemistry and One-Time Inspection Yes Fuel Oil Chemistry, One-Time Inspection, and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Consistent with GALL Report (see SER Section 3.3.2.2.12)
| |
| Stainless steel piping, piping components, and piping elements exposed to lubricating oil (3.3.1
| |
| -33) Loss of material due to pitting, crevice, and MIC Lubricating Oil Analysis and One
| |
| - Time Inspection Yes Lubricating Oil Analysis and One-Time Inspection Consistent with GALL Report (see SER Section 3.3.2.2.12)
| |
| Elastomer seals and components exposed to air
| |
| - indoor uncontrolled (internal or external) (3.3.1
| |
| -34) Loss of material due to wear A plant-specific AMP is to be evaluated.
| |
| Yes External Surfaces Monitoring and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Consistent with GALL Report (see SER Section 3.3.2.2.13)
| |
| Steel with stainless steel cladding pump casing exposed to treated borated water (3.3.1
| |
| -35) Loss of material due to cladding breach A plant-specific AMP is to be evaluated.
| |
| Reference NRC IN 94-63, "Boric Acid Corrosion of Charging Pump Casings Caused by Cladding Cracks."
| |
| Yes Water Chemistry and One-Time Inspection Not applicable to Seabrook (see SER Section 3.3.2.2.14)
| |
| Boraflex spent fuel storage racks neutron-absorbing sheets exposed to treated water (3.3.1
| |
| -36) Reduction of neutron-absorbin g capacity due to boraflex degradation Boraflex Monitoring No Not applicable Not applicable to PWRs (see SER Section 3.3.2.1.1)
| |
| Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation
| |
| | |
| Aging Management Review Results 3-365 Stainless steel piping, piping components, and piping elements exposed to treated water > 140 °F
| |
| (> 60 °C)
| |
| (3.3.1-37) Cracking due to SCC and IGSCC BWR Reactor Water Cleanup System No Not applicable Not applicable to PWRs (see SER Section 3.3.2.1.1)
| |
| Stainless steel piping, piping components, and piping elements exposed to treated water > 140 °F
| |
| (> 60 °C)
| |
| (3.3.1-38) Cracking due to SCC BWR SCC and Water Chemistry No Not applicable Not applicable to PWRs (see SER Section 3.3.2.1.1)
| |
| Stainless steel BWR spent fuel storage racks exposed to treated water > 140 °F (> 60 °C)
| |
| (3.3.1-39) Cracking due to SCC Water Chemistry No Not applicable Not applicable to PWRs (see SER Section 3.3.2.1.1)
| |
| Steel tanks in diesel fuel oil system exposed to air
| |
| - outdoor (external) (3.3.1
| |
| -40) Loss of material due to general, pitting, and crevice corrosion Aboveground Steel Tanks No Not applicable Not applicable to Seabrook (see SER Section 3.3.2.1.1)
| |
| High-strength steel closure bolting exposed to air with steam or water leakage (3.3.1
| |
| -41) Cracking due to cyclic loading and SCC Bolting Integrity No Not applicable Not applicable to Seabrook (see SER Section 3.3.2.1.1)
| |
| Steel closure bolting exposed to air with steam or water leakage (3.3.1
| |
| -42) Loss of material due to general corrosion Bolting Integrity No Not applicable Not applicable to Seabrook (see SER Section 3.3.2.1.1)
| |
| Steel bolting and closure bolting exposed to air
| |
| - indoor uncontrolled (external) or air
| |
| - outdoor (external) (3.3.1
| |
| -43) Loss of material due to general, pitting, and crevice corrosion Bolting Integrity No Bolting Integrity Consistent with GALL Report Steel compressed air system closure bolting exposed to condensation (3.3.1-44) Loss of material due to general, pitting, and crevice corrosion Bolting Integrity No Not applicable Not applicable to Seabrook (see SER Section 3.3.2.1.1)
| |
| | |
| Aging Management Review Results 3-366 Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Steel closure bolting exposed to air
| |
| - indoor uncontrolled (external)
| |
| (3.3.1-45) Loss of preload due to thermal effects, gasket creep, and self
| |
| -loosening Bolting Integrity No Bolting Integrity Consistent with GALL Report Stainless steel and stainless clad steel piping, piping components, piping elements, and heat exchanger components exposed to closed-cycle cooling water > 140 °F (> 60 °C)
| |
| (3.3.1-46) Cracking due to SCC Closed-Cycle Cooling Water System No Not applicable Not applicable to Seabrook (see SER Section 3.3.2.1.1)
| |
| Steel piping, piping components, piping elements, tanks, and heat exchanger components exposed to closed
| |
| -cycle cooling water (3.3.1-47) Loss of material due to general, pitting, and crevice corrosion Closed-Cycle Cooling Water System No Closed-Cycle Cooling Water System Consistent with GALL Report Steel piping, piping components, piping elements, tanks, and heat exchanger components exposed to closed
| |
| -cycle cooling water (3.3.1-48) Loss of material due to general, pitting, crevice, and galvanic corrosion Closed-Cycle Cooling Water System No Closed-Cycle Cooling Water System Consistent with GALL Report (see SER Section 3.3.2.1)
| |
| Stainless steel and steel with stainless steel cladding heat exchanger components exposed to closed
| |
| -cycle cooling water (3.3.1-49) Loss of material due to MIC Closed-Cycle Cooling Water System No Not applicable Not applicable to Seabrook (see SER Section 3.3.2.1.1)
| |
| | |
| Aging Management Review Results 3-367 Stainless steel piping, piping components, and piping elements exposed to closed
| |
| -cycle cooling water (3.3.1-50) Loss of material due to pitting and crevice corrosion Closed-Cycle Cooling Water System No Closed-Cycle Cooling Water System Consistent with GALL Report Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Copper-alloy piping, piping components, piping elements, and heat exchanger components exposed to closed
| |
| -cycle cooling water (3.3.1-51) Loss of material due to pitting, crevice, and galvanic corrosion Closed-Cycle Cooling Water System No Closed-Cycle Cooling Water System Consistent with GALL Report Steel, stainless steel, and copper
| |
| -alloy heat exchanger tubes exposed to closed
| |
| -cycle cooling water (3.3.1-52) Reduction of heat transfer due to fouling Closed-Cycle Cooling Water System No Closed-Cycle Cooling Water System Consistent with GALL Report Steel compressed air system piping, piping components, and piping elements exposed to condensation (internal)
| |
| (3.3.1-53) Loss of material due to general and pitting corrosion Compressed Air Monitoring No Compressed Air Monitoring Consistent with GALL Report Stainless steel compressed air system piping, piping components, and piping elements exposed to internal condensation (3.3.1-54) Loss of material due to pitting and crevice corrosion Compressed Air Monitoring No Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components and External Surfaces Monitoring Consistent with GALL Report (see SER Section 3.3.2.1.2)
| |
| Steel ducting closure bolting exposed to air- indoor uncontrolled (external)
| |
| (3.3.1-55) Loss of material due to general corrosion External Surfaces Monitoring No External Surfaces Monitoring Consistent with GALL Report
| |
| | |
| Aging Management Review Results 3-368 Steel HVAC ducting and components external surfaces exposed to air
| |
| - indoor uncontrolled (external)
| |
| (3.3.1-56) Loss of material due to general corrosion External Surfaces Monitoring No Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Consistent with GALL Report (see SER Section 3.3.2.1.3)
| |
| Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Steel piping and components external surfaces exposed to air- indoor uncontrolled (External) (3.3.1
| |
| -57) Loss of material due to general corrosion External Surfaces Monitoring No External Surfaces Monitoring Consistent with GALL Report Steel external surfaces exposed to air-indoor uncontrolled (external), air
| |
| - outdoor (external), and condensation (external)
| |
| (3.3.1-58) Loss of material due to general corrosion External Surfaces Monitoring No External Surfaces Monitoring and Inspection of Overhead Heavy Load and Light Load (Related to Refueling)
| |
| Handling Systems Consistent with GALL Report Steel heat exchanger components exposed to air
| |
| - indoor uncontrolled (external) or air- outdoor (external) (3.3.1
| |
| -59) Loss of material due to general, pitting, and crevice corrosion External Surfaces Monitoring No External Surfaces Monitoring Consistent with GALL Report Steel piping, piping components, and piping elements exposed to air
| |
| - outdoor (external) (3.3.1
| |
| -60) Loss of material due to general, pitting, and crevice corrosion External Surfaces Monitoring No External Surfaces Monitoring Consistent with GALL Report Elastomer fire barrier penetration seals exposed to air
| |
| -outdoor or air
| |
| - indoor uncontrolled (3.3.1
| |
| -61) Increased hardness, shrinkage, and loss of strength due to weathering Fire Protection No Fire Protection and Structural Monitoring Consistent with GALL Report (see SER Section 3.3.2.1.4)
| |
| | |
| Aging Management Review Results 3-369 Aluminum piping, piping components, and piping elements exposed to raw water (3.3.1
| |
| -62) Loss of material due to pitting and crevice corrosion Fire Protection No Not applicable Not applicable to Seabrook (see SER Section 3.3.2.1.1)
| |
| Steel fire rated doors exposed to air
| |
| -outdoor or air
| |
| - indoor uncontrolled (3.3.1-63) Loss of material due to wear Fire Protection No Not applicable Not applicable to Seabrook (see SER Section 3.3.2.1.1)
| |
| Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Steel piping, piping components, and piping elements exposed to fuel oil (3.3.1-64) Loss of material due to general, pitting, and crevice corrosion Fire Protection and Fuel Oil Chemistry No Fire Protection and Fuel Oil Chemistry Consistent with GALL Report Reinforced concrete structural fire barriers-walls, ceilings, and floors exposed to air
| |
| - indoor uncontrolled (3.3.1-65) Concrete cracking and spalling due to aggressive chemical attack, and reaction with aggregates Fire Protection and Structures Monitoring Program No Not applicable Not applicable to Seabrook (see SER Section 3.3.2.1.1)
| |
| Reinforced concrete structural fire barriers-walls, ceilings, and floors exposed to air
| |
| - outdoor (3.3.1
| |
| -66) Concrete cracking and spalling due to freeze thaw, aggressive chemical attack, and reaction with aggregates Fire Protection and Structures Monitoring Program No Not applicable Not applicable to Seabrook (see SER Section 3.3.2.1.1)
| |
| Reinforced concrete structural fire barriers-walls, ceilings, and floors exposed to air
| |
| - outdoor or air
| |
| -indoor uncontrolled (3.3.1-67) Loss of material due to corrosion of embedded steel Fire Protection and Structures Monitoring Program No Not applicable Not applicable to Seabrook (see SER Section 3.3.2.1.1)
| |
| | |
| Aging Management Review Results 3-370 Steel piping, piping components, and piping elements exposed to raw water (3.3.1
| |
| -68) Loss of material due to general, pitting, crevice, and MIC, and fouling Fire Water System No Fire Water System and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program Consistent with GALL Report (see SER Section 3.3.2.1.5)
| |
| Stainless steel piping, piping components, and piping elements exposed to raw water (3.3.1
| |
| -69) Loss of material due to pitting and crevice corrosion and fouling Fire Water System No Fire Water System Consistent with GALL Report (see SER Section 3.3.2.1.6)
| |
| Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Copper-alloy piping, piping components, and piping elements exposed to raw water (3.3.1
| |
| -70) Loss of material due to pitting, crevice, and MIC, and fouling Fire Water System No Fire Water System and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program Consistent with GALL Report (see SER Section 3.3.2.1.7)
| |
| Steel piping, piping components, and piping elements exposed to moist air or condensation (internal)
| |
| (3.3.1-71) Loss of material due to general, pitting, and crevice corrosion Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components No Compressed Air Monitoring Program and Fire Water System Program Consistent with GALL Report (see SER Section 3.3.2.1.8)
| |
| Steel HVAC ducting and components internal surfaces exposed to condensation (internal)
| |
| (3.3.1-72) Loss of material due to general, pitting, crevice, and (for drip pans and drain lines) MIC Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components No Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Consistent with GALL Report
| |
| | |
| Aging Management Review Results 3-371 Steel crane structural girders in load handling system exposed to air-indoor uncontrolled (external)
| |
| (3.3.1-73) Loss of material due to general corrosion Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems No Inspection of Overhead Heavy Load and Light Load (Related to Refueling)
| |
| Handling Systems and Structural Monitoring Program Consistent with GALL Report (see SER Section 3.3.2.1.9)
| |
| Steel cranes
| |
| -rails exposed to air
| |
| - indoor uncontrolled (external)
| |
| (3.3.1-74) Loss of material due to wear Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems No Inspection of Overhead Heavy Load and Light Load (Related to Refueling)
| |
| Handling Systems Consistent with GALL Report Elastomer seals and components exposed to raw water (3.3.1
| |
| -75) Hardening and loss of strength due to elastomer degradation and loss of material due to erosion Open-Cycle Cooling Water System No Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program Consistent with GALL Report (see SER Section 3.3.2.1.10)
| |
| Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Steel piping, piping components, and piping elements (without lining/
| |
| coating or with degraded lining/coating) exposed to raw water (3.3.1
| |
| -76) Loss of material due to general, pitting, crevice, and MIC, fouling, and lining/coating degradation Open-Cycle Cooling Water System No Buried Piping and Tanks Inspection Consistent with GALL Report (see SER Section 3.3.2.1.11)
| |
| Steel heat exchanger components exposed to raw water (3.3.1
| |
| -77) Loss of material due to general, pitting, crevice, galvanic, and MIC, and fouling Open-Cycle Cooling Water System No Fire Water System Consistent with GALL Report (see SER Section 3.3.2.1.12)
| |
| | |
| Aging Management Review Results 3-372 Stainless steel, nickel alloy, and copper-alloy piping, piping components, and piping elements exposed to raw water (3.3.1
| |
| -78) Loss of material due to pitting and crevice corrosion Open-Cycle Cooling Water System No Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Consistent with GALL Report (see SER Section 3.3.2.1.13)
| |
| Stainless steel piping, piping components, and piping elements exposed to raw water (3.3.1
| |
| -79) Loss of material due to pitting and crevice corrosion, and fouling Open-Cycle Cooling Water System No Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components or Bolting Integrity Consistent with GALL Report (see SER Section 3.3.2.1.14)
| |
| Stainless steel and copper-alloy piping, piping components, and piping elements exposed to raw water (3.3.1
| |
| -80) Loss of material due to pitting, crevice, and MIC Open-Cycle Cooling Water System No Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components or Structural Monitoring Consistent with GALL Report (see SER Section 3.3.2.1.15)
| |
| Copper-alloy piping, piping components, and piping elements, exposed to raw water (3.3.1
| |
| -81) Loss of material due to pitting, crevice, and MIC, and fouling Open-Cycle Cooling Water System No Buried Piping and Tanks Inspection and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Consistent with GALL Report (see SER Section 3.3.2.1.16)
| |
| Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Copper-alloy heat exchanger components exposed to raw water (3.3.1
| |
| -82) Loss of material due to pitting, crevice, galvanic, and MIC, and fouling Open-Cycle Cooling Water System No Open-Cycle Cooling Water System Consistent with GALL Report Stainless steel and copper-alloy heat exchanger tubes exposed to raw water (3.3.1
| |
| -83) Reduction of heat transfer due to fouling Open-Cycle Cooling Water System No Fire Water System Consistent with GALL Report (see SER Section 3.3.2.1.17)
| |
| | |
| Aging Management Review Results 3-373 Copper-alloy > 15% Zn piping, piping components, piping elements, and heat exchanger components exposed to raw water, treated water, or closed-cycle cooling water (3.3.1
| |
| -84) Loss of material due to selective leaching Selective Leaching of Materials No Selective Leaching of Materials Consistent with GALL Report Gray cast iron piping, piping components, and piping elements exposed to soil, raw water, treated water, or closed-cycle cooling water (3.3.1
| |
| -85) Loss of material due to selective leaching Selective Leaching of Materials No Selective Leaching of Materials Consistent with GALL Report Structural steel (new fuel storage rack assembly) exposed to air-indoor uncontrolled (external)
| |
| (3.3.1-86) Loss of material due to general, pitting, and crevice corrosion Structures Monitoring Program No Not applicable Not applicable to Seabrook (see SER Section 3.3.2.1.1)
| |
| Boraflex spent fuel storage racks neutron-absorbing sheets exposed to treated borated water (3.3.1
| |
| -87) Reduction of neutron- absorbi ng capacity due to boraflex degradation Boraflex Monitoring No Not applicable Not applicable to Seabrook (see SER Section 3.3.2.1.1)
| |
| Aluminum and copper-alloy > 15% Zn piping, piping components, and piping elements exposed to air with borated water leakage (3.3.1
| |
| -88) Loss of material due to boric acid corrosion Boric Acid Corrosion No Not applicable Not applicable to Seabrook (see SER Section 3.3.2.1.1)
| |
| Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation Steel bolting and external surfaces exposed to air with borated water leakage (3.3.1
| |
| -89) Loss of material due to boric acid corrosion Boric Acid Corrosion No Boric Acid Corrosion Consistent with GALL Report
| |
| | |
| Aging Management Review Results 3-374 Stainless steel and steel with stainless steel cladding piping, piping components, piping elements, tanks, and fuel storage racks exposed to treated borated water > 140 °F (> 60 °C)
| |
| (3.3.1-90) Cracking due to SCC Water Chemistry No Water Chemistry and One-Time Inspection Consistent with GALL Report Stainless steel and steel with stainless steel cladding piping, piping components, and piping elements exposed to treated borated water (3.3.1-91) Loss of material due to pitting and crevice corrosion Water Chemistry No Water Chemistry and One-Time Inspection Consistent with GALL Report Galvanized steel piping, piping components, and piping elements exposed to air
| |
| - indoor uncontrolled (3.3.1-92) None None No None Consistent with GALL Report Glass piping elements exposed to air, air-indoor uncontrolled (external), fuel oil, lubricating oil, raw water, treated water, and treated borated water (3.3.1
| |
| -93) None None No None Consistent with GALL Report Stainless steel and nickel-alloy piping, piping components, and piping elements exposed to air
| |
| - indoor uncontrolled (external)
| |
| (3.3.1-94) None None No None Consistent with GALL Report Component group (GALL Report Item No.) Aging effect/ mechanism AMP in GALL Report Further evaluation in GALL Report AMP in LRA, supplements, or amendments Staff evaluation
| |
| | |
| Aging Management Review Results 3-375 Steel and aluminum piping, piping components, and piping elements exposed to air- indoor controlled (external)
| |
| (3.3.1-95) None None No None Consistent with GALL Report Steel and stainless steel piping, piping components, and piping elements in concrete (3.3.1
| |
| -96) None None No None Consistent with GALL Report Steel, stainless steel, aluminum, and copper-alloy piping, piping components, and piping elements exposed to gas (3.3.1-97) None None No None Consistent with GALL Report Steel, stainless steel, and copper
| |
| -alloy piping, piping components, and piping elements exposed to dried air (3.3.1-98) None None No None Consistent with GALL Report Stainless steel and copper-alloy < 15% Zn piping, piping components, and piping elements exposed to air with borated water leakage (3.3.1
| |
| -99) None None No None Consistent with GALL Report
| |
| *In the RAI response dated June 19, 2012, the applicant changed items 3.2.1
| |
| -10 and 3.3.1
| |
| -3 from "Not Applicable" to "Applicable" and managed these items with Water Chemistry and One
| |
| -Time Inspection Programs.
| |
| The staff's review of the auxiliary systems component groups followed any one of several approaches. One approach, documented in SER Section 3.3.2.1, reviewed AMR results for components that the applicant indicated are consistent with the GALL Report and require no further evaluation. Another approach, documented in SER Section 3.3.2.2, reviewed AMR results for components that the applicant indicated are consistent with the GALL Report and for which further evaluation is recommended. A third approach, documented in SER Section 3.3.2.3, reviewed AMR results for components that the applicant indicated are not consistent with, or not addressed in, the GALL Report. The staff's review of AMPs credited to manage or monitor aging effects of the auxiliary systems components is documented in SER Section 3.0.3.
| |
| Aging Management Review Results 3-376 3.3.2.1 Aging Management Review Results Consistent with the GALL Report LRA Section 3.3.2.1 identifies the materials, environments, AERMs, and the following programs that manage aging effects for the auxiliary systems components:
| |
| * Aboveground Steel Tanks Program
| |
| * Bolting Integrity Program
| |
| * Boric Acid Corrosion Program
| |
| * Buried Piping and Tanks Inspection Program
| |
| * Closed-Cycle Cooling Water System Program
| |
| * Compressed Air Monitoring Program
| |
| * External Surfaces Monitoring Program
| |
| * Fuel Oil Chemistry Program
| |
| * Fire Protection Program
| |
| * Fire Water System Program
| |
| * Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program
| |
| * Lubricating Oil Analysis Program
| |
| * One-Time Inspection Program
| |
| * Open-Cycle Cooling Water System Program
| |
| * Selective Leaching of Materials Program
| |
| * ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program
| |
| * One-Time Inspection of ASME Code Class 1 Small
| |
| -Bore Piping
| |
| * Water Chemistry Program LRA Tables 3.3.2
| |
| -1 through 3.3.2
| |
| -45 summarize AMRs for the auxiliary system components and indicate AMRs claimed to be consistent with the GALL Report.
| |
| For component groups evaluated in the GALL Report for which the applicant claimed consistency and for which the GALL Report does not recommend further evaluation, the staff performed an audit and review to determine if the plant
| |
| -specific components in these GALL Report component groups were bounded by the GALL Report evaluation.
| |
| The applicant provided a note for each AMR item describing how the information in the tables aligns with the information in the GALL Report. The staff reviewed those AMRs with Notes A-E, which indicate how the AMR was consistent with the GALL Report.
| |
| Note A indicates that the AMR item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. The staff reviewed these items to verify consistency with the GALL Report and the validity of the AMR for the site
| |
| -specific conditions.
| |
| | |
| Aging Management Review Results 3-377 Note B indicates that the AMR item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff reviewed these items to verify consistency with the GALL Report and to ensure that it had reviewed and accepted the identified exceptions to the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant was consistent with the AMP identified in the GALL Report and whether the AMR was valid for the site-specific conditions.
| |
| Note C indicates that the component for the AMR item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the AMP identified by the GALL Report. This note indicates that the applicant was unable to find a listing of some system components in the GALL Report; however, the applicant identified a different component in the GALL Report that had the same material, environment, aging effect, and AMP as the component under review. The staff reviewed these items to verify consistency with the GALL Report. The staff also determined whether the AMR item of the different component applied to the component under review and whether the AMR was valid for the site
| |
| -specific conditions.
| |
| Note D indicates that the component for the AMR item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff reviewed these items to verify consistency with the GALL Report. The staff confirmed whether the AMR item of the different component was applicable to the component under review and whether the exceptions to the GALL Report AMPs was reviewed and accepted by the staff. The staff also determined whether the AMP identified by the applicant was consistent with the AMP identified in the GALL Report and whether the AMR was valid for the site
| |
| -specific conditions.
| |
| Note E indicates that the AMR item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited. The staff reviewed these items to verify consistency with the GALL Report and determined whether the identified AMP would manage the aging effect consistent with the AMP identified in the GALL Report and whether the AMR was valid for the site
| |
| -specific conditions.
| |
| The staff reviewed the information in the LRA. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The staff's evaluation follows.
| |
| LRA Table 3.2.1, item 3.2.1
| |
| -48, addresses stainless steel or stainless steel clad piping, piping components, piping elements, and tanks exposed to treated borated water greater than 140 °F (60 °C), which are being managed for cracking due to SCC. The LRA credits the Water Chemistry Program to manage the aging effect. The GALL Report recommends GALL Report AMP XI.M2, "Water Chemistry," to ensure that these aging effects are adequately managed. The associated AMR items cite generic Notes A and C.
| |
| In its review of components associated with item 3.2.1
| |
| -48 for which the applicant cited generic Note C, the staff noted that LRA Table 3.2.2-3 indicates that stainless steel heat exchanger components (1
| |
| -RH-E-188A and 188B tubes, 1
| |
| -RH-E-9A and 9B channel head, 1
| |
| -RH-E-9A and 9B tube sheet, and 1
| |
| -RH-E-9A and 9B tubes) are subject to cracking due to SCC. The staff also noted that the applicant stated that the aging effect is managed by the Water Chemistry Aging Management Review Results 3-378 Program. The staff further noted that the GALL Report does not contain a specific AMR item for cracking due to SCC of stainless steel heat exchangers exposed to treated borated water greater than 140 °F (60 °C) in the ESFs. However, the staff noted that GALL Report item VII.E1-5 addresses cracking due to SCC of stainless steel heat exchangers exposed to treated borated water greater than 140 °F (60 °C) in the auxiliary systems. Additionally, the GALL AMR item recommends to use the Water Chemistry Program and a plant
| |
| -specific program that verifies the absence of cracking due to SCC. By letter dated January 5, 2011, the staff issued RAI 3.2.2.3
| |
| -01, requesting that the applicant justify how the Water Chemistry Program alone is adequate to manage the aging effect for the heat exchanger components exposed to treated borated water greater than 140 °F (60 °C). As part of the justification, the staff asked the applicant to evaluate the operating experience to clarify whether it supports the AMR results. The staff also requested that, in lieu of a justification, the applicant provide a plant
| |
| -specific program that will confirm the absence of cracking due to SCC in the components and verify the effectiveness of the Water Chemistry Program.
| |
| In its response dated February 3, 2011, the applicant stated that the One
| |
| -Time Inspection Program will be implemented to verify the effectiveness of the Water Chemistry Program for the heat exchanger components exposed to the treated borated water greater than 140 °F (60 °C).
| |
| In its response, the applicant also indicated that LRA Tables 3.2.1, 3.3.1 and 3.2.2
| |
| -3 and LRA Section 3.3.2.2.4.2 were revised accordingly.
| |
| Based on its review, the staff finds the applicant's response to RAI 3.2.2.3
| |
| -01 acceptable because the applicant revised the LRA so that the One
| |
| -Time Inspection Program will be used to verify the effectiveness of the Water Chemistry Program for managing cracking due to SCC of the heat exchanger components in a manner that is consistent with the recommendations in the GALL Report. The staff's concern described in RAI 3.2.2.3
| |
| -01 is resolved.
| |
| The staff reviewed the Water Chemistry Program and One
| |
| -Time Inspection Program and the staff's evaluations are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. In its review, the staff finds the applicant's use of the Water Chemistry Program and One
| |
| -Time Inspection Program acceptable to manage the aging effect for the following reasons:
| |
| * The Water Chemistry Program establishes the plant water chemistry control parameters and their limits to mitigate the environmental effect on the aging.
| |
| * The Water Chemistry Program also takes corrective actions if the parameters exceed the limits so that the environmental effect on the aging is minimized.
| |
| * The One-Time Inspection Program will be implemented to confirm the effectiveness of the Water Chemistry Program, consistent with the recommendations in the GALL Report. LRA Table 3.3.1, item 3.3.1
| |
| -90 addresses stainless steel piping, piping components, piping elements, tanks, and spent fuel rack supports exposed to treated borated water greater than 140 °F (60 °C) which are being managed for cracking due to SCC. The LRA credits the Water Chemistry Program to manage the aging effect. The GALL Report recommends GALL Report AMP XI.M2, "Water Chemistry," to ensure that these aging effects are adequately managed. The associated AMR items cite generic Note A.
| |
| In its review of components associated with item 3.3.1
| |
| -90, for which the applicant cited generic
| |
| | |
| Aging Management Review Results 3-379 Note A, the staff noted that the guidance in the SRP
| |
| -LR and GALL Report was revised in LR-ISG-2011-01, "Aging Management of Stainless Steel Structures and Components in Treated Borated Water," to add the One
| |
| -Time Inspection Program to verify the effectiveness of the Water Chemistry Program to manage stainless steel components for loss of material, cracking, and reduction of heat transfer in treated borated water environments that are not controlled to low oxygen levels. The staff noted that, prior to the issuance of LR
| |
| -ISG-2011-01, the SRP
| |
| -LR and GALL Report guidance inappropriately credited the boron in borated water as a corrosion inhibitor in place of other aging management activities.
| |
| By letter dated May 29, 2012, the staff issued RAI 3.2.1.48
| |
| -1, requesting that the applicant describe how the effectiveness of the Water Chemistry Program to manage cracking due to SCC will be verified for stainless steel components exposed to treated borated water with greater than 5 ppb oxygen. This issue was identified as Open Item OI 3.2.2.1
| |
| -1. In its response dated June 19, 2012, the applicant revised the LRA to add the One
| |
| -Time Inspection Program to verify the effectiveness of the Water Chemistry Program to manage cracking of stainless steel components exposed to treated borated water environments with temperatures greater than 140 °F (60 °C). The staff finds the applicant's response acceptable because the effectiveness of the Water Chemistry Program will be verified to ensure that potential degradation due to SCC does not lead to loss of intended function during the period of extended operation. In addition, the staff evaluated the applicant's Water Chemistry and One
| |
| -Time Inspection Programs and documented the evaluation in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. In its review of components associated with item 3.3.1
| |
| -90, the staff finds the applicant's proposal to manage aging using the Water Chemistry and One
| |
| -Time Inspection Programs acceptable, because the Water Chemistry Program establishes the plant water chemistry control parameters and their limits to mitigate aging and identifies the actions required if the parameters exceed the limits, and the One
| |
| -Time Inspection Program prescribes appropriate visual, surface, or other inspection techniques capable of detecting cracking prior to a loss of intended function, consistent with the revised GALL Report guidance in LR-ISG-2011-01. Based on its review, 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). The staff's concern regarding cracking of components associated with item 3.3.1
| |
| -90 and described in RAI 3.2.1.48
| |
| -1 is resolved.
| |
| LRA Table 3.3.1, item 3.3.1
| |
| -91 addresses stainless steel piping, piping components, piping elements, tanks, and heat exchanger components exposed to treated borated water which are being managed for loss of material due to pitting and crevice corrosion. The LRA credits the Water Chemistry Program to manage the aging effect. The GALL Report recommends GALL Report AMP XI.M2, "Water Chemistry," to ensure that these aging effects are adequately managed. The associated AMR items cite generic Note A or C. The staff noted that the LRA originally included a bolting item that referenced item 3.3.1
| |
| -91 in the spent fuel pool cooling system, citing generic Note E; however, in its response to RAI B.2.1.9
| |
| -1 in a letter dated December 17, 2010, the applicant stated that the subject bolting was not in scope for license renewal and removed the item from the LRA.
| |
| In its review of components associated with item 3.3.1
| |
| -91 for which the applicant cited generic Note A or C, the staff noted that the guidance in the SRP
| |
| -LR and GALL Report was revised in LR-ISG-2011-01, "Aging Management of Stainless Steel Structures and Components in Treated
| |
| | |
| Aging Management Review Results 3-380 Borated Water," to add the One
| |
| -Time Inspection Program to verify the effectiveness of the Water Chemistry Program to manage stainless steel components for loss of material, cracking, and reduction of heat transfer in treated borated water environments that are not controlled to low oxygen levels. The staff noted that, prior to the issuance of LR
| |
| -ISG-2011-01, the SRP
| |
| -LR and GALL Report guidance inappropriately credited the boron in borated water as a corrosion inhibitor in place of other aging management activities. By letter dated May 29, 2012, the staff issued RAI 3.2.1.48
| |
| -1, requesting that the applicant describe how the effectiveness of the Water Chemistry Program to manage loss of material will be verified for stainless steel components exposed to treated borated water with greater than 5 ppb oxygen. This issue was identified as Open Item OI 3.2.2.1
| |
| -1. In its response dated June 19, 2012, and the correction to this response dated July 20, 2012, the applicant revised the LRA to add the One
| |
| -Time Inspection Program to verify the effectiveness of the Water Chemistry Program to manage loss of material for stainless steel components exposed to treated borated water. The staff finds the applicant's response acceptable because the effectiveness of the Water Chemistry Program will be verified to ensure that potential degradation due to corrosion does not lead to loss of intended function during the period of extended operation. In addition, the staff evaluated the applicant's Water Chemistry and One-Time Inspection Programs, documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. In its review of components associated with item 3.3.1
| |
| -91, the staff finds the applicant's proposal to manage aging using the Water Chemistry and One
| |
| -Time Inspection Programs acceptable because the Water Chemistry Program establishes the plant water chemistry control parameters and their limits to mitigate aging and identifies the actions required if the parameters exceed the limits, and the One
| |
| -Time Inspection Program prescribes appropriate visual, volumetric, or other inspection techniques capable of detecting loss of material prior to loss of intended function, consistent with the revised GALL Report guidance in LR-ISG-2011-01. Based on its review, 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). The staff's concern regarding loss of material of components associated with item 3.3.1
| |
| -91 and described in RAI 3.2.1.48
| |
| -1 is resolved.
| |
| The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.1.1 Aging Management Review Results Identified as Not Applicable LRA Table 3.3.1, items 3.3.1-36, 3.3.1-37, 3.3.1-38, and 3.3.1
| |
| -39 state that these items are applicable only to BWRs. The staff confirmed that these items do not apply because the unit is a PWR design. Based on this determination, the staff finds that the applicant provide d an acceptable basis for concluding AMR items 3.3.1
| |
| -36, 3.3.1-37, 3.3.1-38, 3.3.1-39, and 3.3.1
| |
| -49 are not applicable.
| |
| LRA Table 3.3.1, items 3.3.1
| |
| -41, 3.3.1-42, 3.3.1-44 3.3.1-62, 3.3.1-66, 3.3.1-67, 3.3.1-86, 3.3.1-87, 3.3.1-88 state that these items are not applicable to Seabrook. The staff reviewed the LRA and UFSAR and confirmed that the applicant's LRA does not have any AMR results that are applicable for these items.
| |
| | |
| Aging Management Review Results 3-381 LRA Table 3.3.1, item 3.3.1
| |
| -46, addresses stainless steel and stainless steel clad steel piping components and heat exchangers exposed to closed
| |
| -cycle cooling water at temperatures greater than 140 °F (60 °C). The GALL Report recommends the Closed
| |
| -Cycle Cooling Water System Program to manage cracking due to SCC for this component group. The applicant stated that this item is not applicable because this item was not used. The staff evaluated the applicant's claim and found that the primary component cooling water system contains stainless steel components exposed to closed
| |
| -cycle cooling water. In addition, the staff noted that portions of the primary component cooling water system may reach temperatures greater than 140 °F (60 °C), based on information in the applicant's UFSAR. By letter dated January 21, 2011, the staff issued RAI 3.3.1.46
| |
| -1, asking the applicant to clarify whether any stainless steel components in the primary cooling water system are exposed to closed
| |
| -cycle cooling water with temperatures greater than 140 °F (60 °C).
| |
| In its response dated February 18, 2011, the applicant stated that the temperatures provided for the primary component cooling water system in UFSAR Table 9.2
| |
| -7, for the thermal barrier loop heat exchangers, are design temperatures associated with an abnormal event. The applicant also stated that, during normal power operation, the heat exchanger inlet temperature is approximately 86 °F and since the thermal barrier cooling water does not exceed 140 °F, SCC does not need to be addressed in this system. The staff finds the applicant's response and its claim, that this item is not applicable, acceptable because abnormal events need not be postulated for license renewal, as stated in SRP
| |
| -LR Section A.1.2.1, "Applicable Aging Effects." Therefore, the components will not reach temperatures requiring consideration of SCC. The staff's concern described in RAI 3.3.1.46
| |
| -1 is resolved.
| |
| LRA Table 3.3.1, item 3.3.1
| |
| -49, addresses stainless steel and stainless steel clad heat exchanger components exposed to closed
| |
| -cycle cooling water. The GALL Report recommends the Closed
| |
| -Cycle Cooling Water Program to manage loss of material due to MIC for this component group. The applicant stated that this item is not applicable because the GALL Report only includes items associated with BWR systems, and Seabrook is a PWR. The staff evaluated the applicant's claim and found it acceptable because the applicant manages the relevant components for loss of material for other aging mechanisms with the Closed
| |
| -Cycle Cooling Water Program, consistent with the guidance in the GALL Report, which will identify loss of material due to MIC. This issue is also addressed in RAI B.2.1.12
| |
| -7, which is discussed in SER Section 3.0.3.2.4.
| |
| The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing aging effects. On the basis of its review, the staff concludes that the AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed consistent with its AMRs. Therefore, the staff concludes that the applicant 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).
| |
| LRA Table 3.3.1, item 3.3.1
| |
| -63, addresses steel fire rated doors exposed to air
| |
| -outdoor or air
| |
| -indoor uncontrolled. The GALL Report recommends the Fire Protection Program to manage loss of material due to wear for this component group. The applicant stated that this item is not applicable in the auxiliary system; however, loss of material due to wear of steel fire doors exposed to air-outdoor or air
| |
| -indoor uncontrolled is managed by the Fire Protection Program, as Aging Management Review Results 3-382 described in LRA Section 3.5. The staff evaluated the applicant's claim and found it acceptable because steel fire doors were not found in the auxiliary system, and for these components in the containment, structures, and component system described in LRA Section 3.5, the applicant will manage aging with the Fire Protection Program, which is consistent with the guidance in the GALL Report.
| |
| LRA Table 3.3.1, item 3.3.1
| |
| -65, addresses reinforced concrete structural fire barriers, walls, ceilings, and floors exposed to air
| |
| -indoor uncontrolled, which are being managed for concrete cracking and spalling due to aggressive chemical attack and reaction with aggregates. LRA Table 3.3.1, item 3.3.1
| |
| -67, addresses reinforced concrete structural fire barriers, walls, ceilings, and floors exposed to air
| |
| -indoor uncontrolled, which are being managed for loss of material due to corrosion of embedded steel. The GALL Report recommends the Fire Protection and Structures Monitoring Programs to manage concrete cracking and spalling due to aggressive chemical attack and reaction with aggregates and loss of material due to corrosion of embedded steel for this component group. The applicant stated that these items are not applicable to the auxiliary system but are applicable to the containment, structures, and component supports described in LRA Section 3.5. The staff evaluated the applicant's claim and noted that, in LRA Tables 3.5.2
| |
| -4, 3.5.2-5, and 3.5.2-8, the applicant cited LRA Table 3.3.1, item 3.3.1
| |
| -65 or 3.3.1-67 when the Fire Protection Program is proposed to manage aging for reinforced concrete structural fire barriers, and LRA Table 3.3.1, item 3.5.1
| |
| -23, when the Structures Monitoring Program is proposed to manage aging. The staff also noted that, in Table 3.5.2
| |
| -2, the applicant uses the ASME Code Section XI, Subsection IWL Program to manage concrete cracking and spalling using LRA Table 3.5.1, item 3.5.1
| |
| -1, instead of the Structures Monitoring Program. The staff reviewed the applicant's ASME Code Section XI, Subsection IWL Program, and its evaluation is documented in SER Section 3.0.3.2.17. The staff further noted that the applicant's ASME Code Section XI, Subsection IWL Program includes the same or more conservative inspection method and frequency as the Structures Monitoring Program. The staff finds the applicant's claim acceptable because there are no reinforced structural fire barriers, walls, ceilings, and floors in the auxiliary systems, and these components in the containment, structures, and component supports portion of the LRA are either being managed by the Fire Protection and Structures Monitoring Programs or by acceptable alternative items.
| |
| 3.3.2.1.2 Loss of Material Due to Pitting and Crevice Corrosion LRA Table 3.3.1, item 3.3.1
| |
| -54, addresses stainless steel compressed air system piping, piping components, and piping elements exposed to internal condensation, which are being managed for loss of material due to pitting and crevice corrosion. Stainless steel piping components exposed to external condensation are being managed for loss of material due to pitting and crevice corrosion. The LRA credits the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage the aging effect for internal condensation and the External Surfaces Monitoring Program to manage the aging effect for external condensation. The GALL Report recommends GALL Report AMP XI.M24, "Compressed Air Monitoring" to ensure that these aging effects are adequately managed. The associated AMR items cite generic Note E.
| |
| GALL Report AMP XI.M24 recommends using visual inspections of stainless and carbon steels to detect the effects of corrosion or presence of contaminants. In its review of components associated with LRA Table 3.3.1, item 3.3.1-54, for which the applicant cited generic Note E, the Aging Management Review Results 3-38 3 staff noted that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program or the External Surfaces Monitoring Program proposes to manage the aging of piping and fittings, valve bodies, tanks, traps, flexible hoses, and orifices through the use of visual surface inspections (during periodic maintenance and via work order for components identified as requiring aging management) for evidence of hardening and loss of strength, loss of material, and reduction of heat transfer due to fouling.
| |
| The staff's evaluations of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program and the External Surfaces Monitoring Program are documented in SER Sections 3.0.3.2.15 and 3.0.3.2.14, respectively. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -54, the staff finds the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program for stainless steel compressed air system piping, piping components, and piping elements exposed to internal condensation, and the External Surfaces Monitoring Program for stainless steel piping components exposed to external condensation acceptable. These programs will manage loss of material for the relevant in
| |
| -scope stainless steel components through visual inspections which will be performed by qualified personnel during the performance of periodic, predictive, and corrective maintenance and surveillance testing. The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.1.3 Loss of Material Due to General Corrosion
| |
| - HVAC Ducting and Components LRA Table 3.3.1, item 3.3.1
| |
| -56, addresses steel HVAC ducting and components external surfaces exposed to air
| |
| -indoor uncontrolled (external), which are being managed for loss of material due to general corrosion. The applicant credits the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage the aging effect for steel fan housings exposed to air
| |
| -indoor uncontrolled (internal). The GALL Report recommends GALL Report AMP XI.M36, "External Surfaces Monitoring," to ensure that these aging effects are adequately managed. The associated AMR items cite generic Note E. The applicant stated that components that have the same internal and external environments have the same aging effects on both the internal and external surfaces.
| |
| GALL Report AMP XI.M36 recommends using visual inspections of the external surfaces o f components for general corrosion to manage the aging effect for the item. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -56, for which the applicant cited generic Note E, the staff noted that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program proposes to manage the aging of structures and structural components through the use of opportunistic inspections of the internal surfaces of components. The staff also noted that, since the components have the same internal and external environments, the loss of material aging effect is the same on both the internal and external surfaces; therefore, GALL Report, item VII.F4
| |
| -1, which refers to air
| |
| -indoor uncontrolled (external) environment and the loss of material aging mechanism, would also apply to an air
| |
| -indoor uncontrolled (internal) environment.
| |
| | |
| Aging Management Review Results 3-384 The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Program is documented in SER Section 3.0.3.2.15. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -56, the staff finds the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Program acceptable because it includes visual inspections that can detect loss of material on the internal surfaces of components.
| |
| The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.1.4 Increased Hardness, Shrinkage, and Loss of Strength Due to Weathering LRA Table 3.3.1, item 3.3.1
| |
| -61, addresses elastomer fire barrier penetration seals exposed to air-outdoor or air
| |
| -indoor uncontrolled, which are being managed for increased hardness, shrinkage, and loss of strength due to weathering. The applicant credits the Fire Protection or Structures Monitoring Program to manage the aging effect. The GALL Report recommends GALL Report AMP XI.M26, "Fire Protection," to ensure that these aging effects are adequately managed. The associated AMR items cite generic Note A when they are managed by the Fire Protection Program and generic Note E when they are managed by the Structures Monitoring Program. GALL Report AMP XI.M26 recommends using visual inspections for 10 percent of each type of seal at least once every RFO to manage the aging of these items. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -61, for which the applicant cited generic Note E, the staff noted that the Structures Monitoring Program will be used to manage the aging of elastomer seals through the use of visual inspections performed on a 5-year basis.
| |
| The staff's evaluation of the applicant's Structures Monitoring Program is documented in SER Section 3.0.3.2.18. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -61, the staff noted that the components that cite generic Note E and do not have a corresponding item that credits the Fire Protection Program are not fire barriers but other types of elastomer seals, such as pressure or flood barriers. The staff also noted that LRA Table 3.3.1, item 3.3.1
| |
| -61, is specifically for fire barrier elastomer seals, and the Fire Protection Program is not applicable for non
| |
| -fire barrier elastomer seals. The staff further noted that non
| |
| -fire barrier elastomer seals may be constructed of materials that are sensitive to ultraviolet light, radiation, or ozone; therefore, tactile examination techniques
| |
| -such as scratching, bending, folding, stretching or pressing
| |
| -are recommended in conjunction with visual examinations to manage the effects of aging. The applicant's Structures Monitoring Program does not include tactile examination techniques. By letter dated January 21, 2011 (ADAMS Accession No. ML110070128), the staff issued RAI 3.3.1.61
| |
| -1, requesting that the applicant clarify whether the non-fire barrier elastomer seals being managed for aging by the Structures Monitoring Program are subject to hardening and loss of strength due to exposure to ultraviolet light, radiation, or ozone. If the materials are subject to hardening and loss of strength and exposed to these aging effects, the staff asked the applicant to explain how the Structures Monitoring Program is adequate to manage aging for these components.
| |
| In its response dated February 18, 2011(ADAMS Accession No. ML110530481), the applicant stated that the Structures Monitoring Program manages non
| |
| -fire barrier elastomer seals that are Aging Management Review Results 3-385 subject to aging effects of increased hardness, shrinkage, and loss of strength for all environments including ultraviolet light, radiation, and ozone. The applicant also stated that it will perform both visual and tactile examinations, when required, for non
| |
| -fire barrier elastomer seals to ensure the seal's integrity. The applicant further stated that the Structures Monitoring Program will be updated to provide tactile examination techniques for the non
| |
| -fire barrier elastomer seals. The staff finds the applicant's response acceptable because the applicant will enhance its Structures Monitoring Program to include tactile examination techniques for the non-fire barrier elastomer seals, which is an appropriate technique for managing the hardening and loss of strength and is consistent with the GALL Report recommendations. The staff's concern described in RAI 3.3.1.61
| |
| -1 is resolved.
| |
| The staff's evaluation of the applicant's Structures Monitoring Program is documented in SER Section 3.0.3.2.18. In its review of components associated with item 3.3.1
| |
| -61, the staff noted that the components that cite generic Note E and do not have a corresponding item being managed by the Fire Protection Program, are not fire barriers but are other types of elastomer seals, such as pressure or flood barriers. The staff also noted that item 3.3.1
| |
| -61 is specifically for fire barrier elastomer seals, and the Fire Protection Program is not applicable for non
| |
| -fire barrier elastomer seals. The staff finds the applicant's proposal to manage non
| |
| -fire barrier elastomer seals using the Structures Monitoring Program acceptable because the program includes visual inspections and tactile examinations, which are capable of detecting increased hardness, shrinkage, and loss of strength for elastomer seals.
| |
| The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.1.5 Loss of Material Due to General, Pitting, Crevice, and Microbiologically
| |
| -Influenced Corrosion and Fouling LRA Table 3.3.1, item 3.3.1
| |
| -68, addresses steel piping, piping components, and piping elements exposed to raw water, which are being managed for loss of material due to general, pitting, crevice, and MIC and fouling. The staff noted that the LRA states that galvanic corrosion is an additional aging effect that will be managed for several systems. The LRA credits the Fire Water System to manage the aging effects for components in the fire protection system and the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage the aging effects for components in the chlorination, dewatering, plant floor drain, potable water, roof drains, screen wash, waste processing liquid, and waste processing liquid drains systems. The GALL Report recommends GALL Report AMP XI.M27, "Fire Water System," to ensure that these aging effects are adequately managed. The associated AMR items that credit the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program cite generic Note E and plant
| |
| -specific notes that state the components are not associated with the fire water system.
| |
| GALL Report AMP XI.M27 recommends using non
| |
| -intrusive examination techniques (e.g., volumetric testing) to detect changes in the wall thickness. GALL Report AMP XI.M27 also recommends visual inspections of the interior pipe surfaces as an alternative to non
| |
| -intrusive examinations, as long as inspections are performed on a representative number of locations on a reasonable basis and can evaluate wall thickness and the inner diameter of the piping to
| |
| | |
| Aging Management Review Results 3-386 manage the aging of these items. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -68, for which the applicant cited generic Note E, the staff noted that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program proposes to manage the aging of steel piping, piping components, and piping elements through the use of visual inspections performed on an opportunistic basis.
| |
| The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff noted that LRA Table 3.3.1, item 3.3.1
| |
| -68, states that loss of material due to fouling is not an applicable aging effect for components in the potable water system. However, the staff also noted that GALL Report Table 3, item 68, states that steel components exposed to raw water have an aging effect of loss of material due to fouling. While the applicant has stated that the environment is potable water, given that there are no chemistry controls for its potable water, its effect on items would be similar to raw water. Nevertheless, the staff also noted that the inspections performed by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program for loss of material due to corrosion are the same as those to identify loss of material due to fouling. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -68, the staff finds the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program acceptable. This program will conduct visual inspections of the internal surfaces of the components, which is equivalent to the recommendations in GALL Report AMP XI.M27 for managing aging of these types of components.
| |
| The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.1.6 Loss of Material Due to Pitting and Crevice Corrosion and Fouling LRA Table 3.3.1, item 3.3.1
| |
| -69, addresses stainless steel piping, piping components, and piping elements exposed to raw water, which are being managed for loss of material due to pitting and crevice corrosion and fouling. The staff noted that the LRA states that MIC is an additional aging effect that will be managed for a few systems. The LRA credits the Fire Water System Program to manage the aging effects for components in the fire protection system and the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage the aging effects for components in the plant floor drain, potable water, and waste processing liquid drains systems. The GALL Report recommends GALL Report AMP XI.M27, "Fire Water System," to ensure that these aging effects are adequately managed. The associated AMR items that credit the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program cite generic Note E indicating that the AMR item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited.
| |
| GALL Report AMP XI.M27 recommends using non
| |
| -intrusive examination techniques (e.g., volumetric testing) to detect changes in the wall thickness. GALL Report AMP XI.M27 also recommends visual inspections of the interior pipe surfaces as an alternative to non
| |
| -intrusiv e examinations, as long as inspections are performed on a representative number of locations on a reasonable basis and can evaluate wall thickness and the inner diameter of the piping to manage the aging of these items. In its review of components associated with LRA Table 3.3.1, Aging Management Review Results 3-387 item 3.3.1
| |
| -69, for which the applicant cited generic Note E, the staff noted that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program proposes to manage the aging of stainless steel piping, piping components, and piping elements through the use of visual inspections performed on an opportunistic basis.
| |
| The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff noted that LRA Table 3.3.1, item 3.3.1
| |
| -69, states that loss of material due to fouling is not an applicable aging effect for components in the potable water system. However, the staff also noted that GALL Report Table 3, item 69, states that steel components exposed to raw water have an aging effect of loss of material due to fouling. While the applicant has stated that the environment is potable water, given that there are no chemistry controls for its potable water, its effect on items would be similar to raw water. Nevertheless, the staff also noted that the inspections performed by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program for loss of material due to corrosion are the same as those to identify loss of material due to fouling. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -69, the staff finds the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program acceptable. This program will conduct visual inspections of the internal surfaces of components, which is equivalent to the recommendations in GALL Report AMP XI.M27 for managing aging of these types of components.
| |
| The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.1.7 Loss of Material Due to Pitting, Crevice, and Microbiologically
| |
| -Influenced Corrosion and Fouling LRA Table 3.3.1, item 3.3.1
| |
| -70, addresses copper piping, piping components, and piping elements exposed to raw water, which are being managed for loss of material due to pitting, crevice, and MIC and fouling. The staff noted that the LRA states that this item will manage the additional aging effect of galvanic corrosion for components in the potable water system. The LRA credits the Fire Water System Program to manage the aging effects for components in the fire protection system and the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage the aging effects for components in the potable water system. The GALL Report recommends GALL Report AMP XI.M27, "Fire Water System," to ensure that these aging effects are adequately managed. The associated AMR items, which credit the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, cite generic Note E indicating that the AMR item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited.
| |
| GALL Report AMP XI.M27 recommends using non
| |
| -intrusive examination techniques (e.g., volumetric testing) to detect changes in the wall thickness. GALL Report AMP XI.M27 also recommends visual inspections of the interior pipe surfaces as an alternative to non
| |
| -intrusive examinations, as long as inspections are performed on a representative number of locations on a reasonable basis and can evaluate wall thickness and the inner diameter of the piping to manage the aging of these items. In its review of components associated with LRA Table 3.3.1, Aging Management Review Results 3-388 item 3.3.1
| |
| -70, for which the applicant cited generic Note E, the staff noted that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program also proposes to manage the aging of copper piping, piping components, and piping elements through the use of visual inspections performed on an opportunistic basis.
| |
| The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff noted that LRA Table 3.3.1, item 3.3.1
| |
| -70, states that loss of material due to fouling is not an applicable aging effect for components in the potable water system. However, the staff also noted that GALL Report Table 3, item 70, states that steel components exposed to raw water have an aging effect of loss of material due to fouling. While the applicant has stated that the environment is potable water, given that there are no chemistry controls for its potable water, its effect on items would be similar to raw water. Nevertheless, the staff also noted that the inspections performed by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program for loss of material due to corrosion are the same as those to identify loss of material due to fouling. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -70, the staff finds the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program acceptable. This program will conduct visual inspections of the internal surfaces of components, which is equivalent to the recommendations in GALL Report AMP XI.M27 for managing aging of these types of components.
| |
| The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.1.8 Loss of Material Due to General, Pitting, and Crevice Corrosion As amended by letter dated March 5, 2014, LRA Table 3.3.1, item 3.3.1
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| -71, addresses steel and gray cast iron piping components and piping elements exposed to moist air or condensation (internal), which are being managed for (a) loss of material due to general, pitting, crevice, and galvanic corrosion and (b) MIC. The applicant credits the Compressed Air Monitoring and Fire Water System Programs to manage aging for steel and gray cast iron filter and dryer housings, piping and fittings, trap, filter housing, and valve body components. The GALL Report recommends GALL Report AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting," to ensure that the aging effect is adequately managed. The associated AMR items cite generic Notes A and E. The associated AMR items also cite a plant
| |
| -specific note, which states that the Compressed Air Monitoring Program is substituted to manage the aging effect applicable to this component type, material, and environment combination because the diesel generator starting air is part of the Compressed Air Monitoring Program at the station. Therefore, the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Program is not applicable. The applicant also stated that the Fire Water System Program will be used to manage aging effects associated with fire water system components, which is consistent with LR-ISG-2012-02. GALL Report AMP XI.M38 recommends using periodic visual inspections of internal surfaces. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -71, for which the applicant cited generic Note E, the staff noted that the Compressed Air Monitoring Program also proposes to manage the aging of steel piping, piping components, and piping elements exposed Aging Management Review Results 3-389 to moist air or condensation (internal) through the use of air quality monitoring and visual inspections.
| |
| The staff's evaluation of the applicant's Compressed Air Monitoring and Fire Water System Programs is documented in SER Sections 3.0.3.2.6 and 3.0.3.2.8, respectively. The Compressed Air Monitoring Program proposes to manage the aging of steel components by monitoring air quality and dew point and performing visual inspections. The Compressed Air Monitoring Program includes in
| |
| -line dew point monitors, which verify the dew point of instrument air to be sure it is within the calculated limit and in
| |
| -line filters which limit air particle size. The Compressed Air Monitoring Program also includes air sampling to ensure compliance with air quality standards. In addition, the applicant stated that the system is subject to a New Hampshire State inspection, which is a visual inspection of the system. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -71, the staff finds the applicant's proposal to manage aging using the Compressed Air Monitoring Program acceptable because, like the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, it will perform visual inspections that can detect loss of material prior to the loss of component function. The staff finds the applicant's proposal to manage aging using the Fire Water System Program for fire water system components acceptable because it is consistent with LR-ISG-2012-02 AMP XI.M27, for which periodic internal inspections capable of detecting loss of material will be conducted.
| |
| The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.1.9 Loss of Material Due to General Corrosion
| |
| - Steel Crane Structural Girders LRA Table 3.3.1, item 3.3.1
| |
| -73, addresses steel crane structural girders in load handling system exposed to air
| |
| -indoor uncontrolled (external), which are being managed for loss of material due to general corrosion. The LRA credits the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems and Structural Monitoring Programs to manage the aging effect. The GALL Report recommends GALL Report AMP XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems," to ensure that this aging effect is adequately managed. The associated AMR items cite generic Note E and plant-specific Note 514, which states that the applicant will use the Structural Monitoring Program in addition to the recommended GALL Report AMP.
| |
| For those items associated with generic Note E, GALL Report AMP XI.M23 recommends using visual inspections on a routine basis to manage the aging of these items. In its review of components associated with item 3.3.1
| |
| -73, for which the applicant cited generic Note E, the staff noted that the Structural Monitoring Program also includes the use of visual inspections to manage the aging of steel crane structural girders in the load handling system.
| |
| The staff's evaluation of the applicant's Structural Monitoring Program is documented in SER Section 3.0.3.2.18. The staff noted that the applicant is using the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program, documented in SER Section 3.0.3.2.5, as well as the Structural Monitoring Program, and visual inspections are included in both programs. The staff also noted the Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program performs visual inspections of structural Aging Management Review Results 3-390 supports of overhead cranes yearly, while the Structures Monitoring Program determines the frequency of the inspections in accordance with the characteristics of the environment in which the structures are located. For structures in harsh environments, the inspections are conducted on a 5-year basis and those in mild environments are done on a 10
| |
| -year basis. In its review of components associated with item 3.3.1
| |
| -73, the staff finds the applicant's proposal to manage aging using dual programs, the Structural Monitoring Program and the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program, acceptable. Visual inspections of cranes structural components' will be performed at least annually to manage their aging effects so they can continue to fulfill their function(s) for the period of extended operation.
| |
| The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 3.3.2.1.10 Hardening and Loss of Strength Due to Elastomer Degradation; Loss of Material Due to Erosion LRA Table 3.3.1, item 3.3.1
| |
| -75, addresses elastomer seals and components exposed to raw water, which are being managed for hardening and loss of strength due to elastomer degradation and loss of material due to erosion. The applicant credits the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage the aging effect. The GALL Report recommends GALL Report AMP XI.M20, "Open
| |
| -Cycle Cooling Water System," to ensure that these aging effects are adequately managed. The associated AMR items cite generic Note E indicating that the AMR item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited.
| |
| GALL Report AMP XI.M20 recommends using condition and performance monitoring programs to manage the aging of these items. In addition, GALL Report AMP XI.M20 recommends using chemical treatments whenever the potential for biological fouling species exists and also recommends the use of periodic flushing. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -75, for which the applicant cited generic Note E, the staff noted that the applicant also proposed to use the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage the aging of elastomer seals and components through the use of periodic inspection on the internal surfaces of components. It was not clear to the staff how the opportunistic visual inspections will be able to manage aging of components in a raw water system that does not include chemical treatments or surveillances. By letter dated January 5, 2011, the staff issued RAI 3.3.2.2
| |
| -1, asking the applicant to justify using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, which is only a visual inspection program, to manage aging in the raw water environment.
| |
| In its response dated February 3, 2011, the applicant stated that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program was chosen because the internal raw water environments are not covered by any other AMP. The applicant also stated that its conclusion to use this AMP is supported by information in Revision 2 to the GALL Report, that this program applies to components exposed to any water systems not included in the open-cycle cooling water, closed treated water, or fire water AMPs. The applicant further stated that its equipment inspections have been successful at identifying and resolving Aging Management Review Results 3-391 corrosion or degradation before it affects the ability of the component to perform its intended function. The staff finds the applicant's response acceptable because the GALL Report, Revision 2, allows components exposed to raw water, that are not part of the open
| |
| -cycle cooling water system, to be managed with the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Component Program; therefore, the applicant's proposal complies with the current staff position. The staff's concern described in RAI 3.3.2.2
| |
| -1 is resolved.
| |
| The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -75, the staff finds the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, and the response to RAI 3.3.2.2
| |
| -1, acceptable for the following reasons:
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| * The program conducts inspections during periodic system surveillances or maintenance activities when internal surfaces are accessible.
| |
| * The inspections consist of visual examinations and non
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| -visual examinations, such as tactile techniques that are capable of detecting hardening and loss of strength in elastomers.
| |
| * The raw water environment is associated with groundwater that is not capable of being chemical treated or for which there are no applicable performance tests associated with groundwater dewatering systems, as related to managing the aging of elastomers.
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| In addition, the staff finds that the use of Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is acceptable to manage the elastomers exposed to raw water because the raw water is associated with the dewatering system and not the open
| |
| -cycle cooling system, so the use of this program is consistent with NUREG
| |
| -2221, "Technical Bases for Changes in the Subsequent License Renewal Guidance Documents NUREG
| |
| -2191 and NUREG-2192." The staff's concern described in RAI 3.3.2.2
| |
| -1 is resolved.
| |
| The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.1.11 Loss of Material Due to General, Pitting, Crevice, and Microbiologically
| |
| -Influenced Corrosion, Fouling, and Lining/Coating Degradation LRA Table 3.3.1, item 3.3.1
| |
| -76, addresses steel piping, piping components, and piping elements (without lining or coating or with degraded lining or coating) exposed to raw water, which are being managed for loss of material due to general, pitting, and crevice corrosion, MIC, fouling, and lining or coating degradation. The applicant credits the Buried Piping and Tanks Inspection Program to manage the aging effect. The GALL Report recommends GALL Report AMP XI.M.20, "Open
| |
| -Cycle Cooling Water System," to ensure that these aging effects are adequately managed. The associated AMR item cites generic Note E indicating that the AMR item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited.
| |
| | |
| Aging Management Review Results 3-392 GALL Report AMP XI.M.20 recommends using coatings to protect the metal surfaces from being exposed to aggressive environments and visual inspections to manage the aging of these items. In its review of components associated with LRA Table 3.3.1, item3.3.1
| |
| -76, for which the applicant cited generic Note E, the staff noted that the Buried Piping and Tanks Inspection Program proposes to manage the aging of steel piping, piping components, and piping elements through the use of coatings to protect the metal surfaces from being exposed to aggressive environments and visual inspections.
| |
| The staff's evaluation of the applicant's Buried Piping and Tanks Inspection Program is documented in SER Section 3.0.3.3.1. The staff noted that the raw water that this item is exposed to is groundwater seepage into a vault in which the piping is routed. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -76, the staff finds the applicant's proposal to manage aging using the Buried Piping and Tanks Inspection Program acceptable for the following reasons:
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| * The program includes preventive actions, such as external coatings and wrappings, installed to industry standard practices.
| |
| * Periodic visual inspections will be performed starting 10 years prior to the period of extended operation and extend into both 10
| |
| -year periods during the period of extended operation to ensure that coatings remain intact.
| |
| * Plant-specific operating experience will be used to inform inspection locations.
| |
| The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.1.12 Loss of Material Due to General, Pitting, Crevice, and Microbiologically
| |
| -Influenced Corrosion, and Fouling LRA Table 3.3.1, item 3.3.1
| |
| -77, addresses steel heat exchanger components exposed to raw water, which are being managed for loss of material due to general, pitting, and crevice corrosion, MIC, and fouling. The applicant credits the Fire Water System Program to manage the aging effect. The GALL Report recommends GALL Report AMP XI.M20, "Open
| |
| -Cycle Cooling Water System," to ensure that these aging effects are adequately managed. The associated AMR items cite generic Note E indicating that the AMR item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited.
| |
| GALL Report AMP XI.M20 recommends using condition and performance monitoring programs to manage the aging of these items. In addition, GALL Report AMP XI.M20 recommends using chemical treatments whenever the potential for biological fouling species exists and also recommends the use of periodic flushing. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -77, for which the applicant cited generic Note E, the staff noted that the Fire Water System Program proposes to manage the aging of steel heat exchanger components through the use of inspections, periodic flushing, system performance testing, and chemical additions to prevent microbiological growth.
| |
| The staff's evaluation of the applicant's Fire Water System Program is documented in SER Section 3.0.3.2.8. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -77, Aging Management Review Results 3-393 the staff finds the applicant's proposal to manage aging using the Fire Water System Program acceptable because the program conducts inspections roughly every outage and uses preventive actions, including chemical additions and performance verification.
| |
| The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.1.13 Loss of Material Due to Pitting and Crevice Corrosion LRA Table 3.3.1, item 3.3.1-78, addresses stainless steel, nickel alloy, and copper
| |
| -alloy piping, piping components, and piping elements exposed to raw water, which are being managed for loss of material due to pitting and crevice corrosion. The applicant credits the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage the aging effect. The GALL Report recommends GALL Report AMP XI.M20, "Open
| |
| -Cycle Cooling Water System," to ensure that these aging effects are adequately managed. The associated AMR items cite generic Note E indicating that the AMR item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited.
| |
| GALL Report AMP XI.M20 recommends using condition and performance monitoring programs to manage the aging of these items. In addition, GALL Report AMP XI.M20 recommends using chemical treatments whenever the potential for biological fouling species exists and also recommends the use of periodic flushing. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -78, for which the applicant cited generic Note E, the staff noted that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program proposes to manage the aging of stainless steel, nickel alloy, and copper
| |
| -alloy piping, piping components, and piping elements through the use of periodic inspection on the internal surfaces of components. It was not clear to the staff how the opportunistic visual inspections will be able to manage aging of components in a raw water system that does not include chemical treatments or surveillances. By letter dated January 5, 2011, the staff issued RAI 3.3.2.2-1, requesting that the applicant justify the use of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, which is only a visual inspection program, to manage aging in the raw water environment.
| |
| In its response dated February 3, 2011, the applicant stated that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program was chosen because the internal raw water environments are not covered by any other AMP. The applicant also stated that its conclusion to use this AMP is supported by information in Revision 2 to the GALL Report, that this program applies to components exposed to any water systems not included in the open-cycle cooling water, closed treated water, or fire water AMPs. The applicant further stated that its equipment inspections have been successful at identifying and resolving corrosion or degradation before it affects the ability of the component to perform its intended function. The staff finds the applicant's response acceptable because the GALL Report, Revision 2, allows components exposed to raw water, that are not part of the open
| |
| -cycle cooling water system, to be managed with the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Component Program; therefore, the applicant's proposal complies with the current staff position. The staff's concern described in RAI 3.3.2.2
| |
| -1 is resolved.
| |
| | |
| Aging Management Review Results 3-394 The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -78, the staff finds the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program acceptable. The program conducts visual inspections during periodic system surveillances or maintenance activities when internal surfaces are accessible and monitors parameters such as corrosion, corrosion byproducts, coating degradation, scale/deposits, pits, and surface discoloration and discontinuities. In addition, the staff finds that the use of Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is acceptable to manage these components exposed to raw water because the raw water is associated with the chlorination and screen wash system and not the open
| |
| -cycle cooling system. Therefore, the use of this program is consistent with the current staff position in the GALL Report, Revision 2.
| |
| The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.1.14 Loss of Material Due to Pitting and Crevice Corrosion, and Fouling LRA Table 3.3.1, item 3.3.1
| |
| -79, addresses stainless steel piping, piping components, and piping elements exposed to raw water, which are being managed for loss of material due to pitting and crevice corrosion, and fouling. The applicant credits either the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program or Bolting Integrity Program to manage the aging effect. The GALL Report recommends GALL Report AMP XI.M20, "Open
| |
| -Cycle Cooling Water System," to ensure that these aging effects are adequately managed. The associated AMR items cite generic Note E indicating that the AMR item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited.
| |
| GALL Report AMP XI.M20 recommends using condition and performance monitoring programs to manage the aging of these items. In addition, GALL Report AMP XI.M20 recommends using chemical treatments whenever the potential for biological fouling species exists and also recommends the use of periodic flushing. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -79, for which the applicant cited generic Note E, the staff noted that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program proposes to manage the aging of stainless steel piping, piping components, and piping elements through the use of periodic inspection on the internal surfaces of components. The staff also noted that the Bolting Integrity Program proposes to manage the aging of stainless steel bolts through the use of periodic inspection.
| |
| The staff's evaluation of the applicant's Bolting Integrity Program is documented in SER Section 3.0.3.1.7. The staff notes that the GALL Report mainly recommends managing aging of bolts with the Bolting Integrity Program. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -79, the staff finds the applicant's proposal to manage aging using the Bolting Integrity Program acceptable because it follows the ASME Code guidelines for managing aging of bolts, which incorporates operating experience specifically for this component type.
| |
| For the components other than bolting, it was not clear to the staff how the opportunistic visual inspections will be able to manage aging of components in a raw water system that does not Aging Management Review Results 3-395 include chemical treatments or surveillances. By letter dated January 5, 2011, the staff issued RAI 3.3.2.2
| |
| -1, requesting that the applicant justify the use of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, which is only a visual inspection program to manage aging in the raw water environment.
| |
| In its response dated February 3, 2011, the applicant stated that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program was chosen because the internal raw water environments are not covered by any other AMP. The applicant also stated that its conclusion to use this AMP is supported by information in Revision 2 to the GALL Report, that this program applies to components exposed to any water systems not included in the open-cycle cooling water, closed treated water, or fire water AMPs. The applicant further stated that its equipment inspections have been successful at identifying and resolving corrosion or degradation before it affects the ability of the component to perform its intended function. The staff finds the applicant's response acceptable because the GALL Report, Revision 2, allows for components exposed to raw water, that are not part of the open
| |
| -cycle cooling water system, to be managed with the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Component Program. Therefore, the applicant's proposal complies with the current staff position. The staff's concern described in RAI 3.3.2.2
| |
| -1 is resolved.
| |
| The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -79, the staff finds the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program acceptable. This program conducts visual inspections durin g periodic system surveillances or maintenance activities when internal surfaces are accessible and monitors parameters such as corrosion, corrosion byproducts, coating degradation, scale/deposits, pits, and surface discoloration and discontinuities. In addition, the staff finds that the use of Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is acceptable to manage the component exposed to raw water because the raw water is associated with the dewatering, service water, and screen wash systems and not the open
| |
| -cycle cooling system. Therefore, the use of this program is consistent with the current staff position in the GALL Report, Revision 2.
| |
| The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.1.15 Loss of Material Due to Pitting, Crevice, and Microbiologically
| |
| -Influenced Corrosion LRA Table 3.3.1, item 3.3.1
| |
| -80, addresses stainless steel and copper piping, piping components, and piping elements exposed to raw water, which are being managed for loss of material due to pitting and crevice corrosion and MIC. The applicant credits either the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program or Structures Monitoring Program to manage the aging effect. The GALL Report recommends GALL Report AMP XI.M20, "Open
| |
| -Cycle Cooling Water System," to ensure that these aging effects are adequately managed. The associated AMR items cite generic Note E indicating that the AMR item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited.
| |
| | |
| Aging Management Review Results 3-396 GALL Report AMP XI.M20 recommends using condition and performance monitoring programs to manage the aging of these items. In addition, GALL Report AMP XI.M20 recommends using chemical treatments whenever the potential for biological fouling species exists and also recommends the use of periodic flushing. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -80, for which the applicant cited generic Note E, the staff noted that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program proposes to manage the aging of stainless steel and copper piping, piping components, and piping elements through the use of periodic inspection on the internal surfaces of components. The staff also noted that the Structures Monitoring Program proposes to manage the aging of stainless steel sumps through the use of periodic inspections conducted on a 5
| |
| -year basis. It was not clear to the staff how the opportunistic visual inspections will be able to manage aging of components in a raw water system that does not include chemical treatments or surveillances. By letter dated January 5, 2011, the staff issued RAI 3.3.2.2
| |
| -1, requesting that the applicant justify the use of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, which is only a visual inspection program to manage aging in the raw water environment. In addition, by letter dated January 5, 2011, the staff issued RAI 3.5.2.5-2, requesting that the applicant justify the use of the Structures Monitoring Program, which is only a visual inspection program, to manage aging in the raw water environment.
| |
| In its response dated February 3, 2011, the applicant stated that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program was chosen because the internal raw water environments are not covered by any other AMP. The applicant also stated that its conclusion to use this AMP is supported by information in Revision 2 to the GALL Report, that this program applies to components exposed to any water systems not included in the open-cycle cooling water, closed treated water, or fire water AMPs. The applicant furthe r stated that its equipment inspections have been successful at identifying and resolving corrosion or degradation before it affects the ability of the component to perform its intended function. The staff finds the applicant's response acceptable because the GALL Report, Revision 2, allows components exposed to raw water, that are not part of the open
| |
| -cycle cooling water system, to be managed with the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Component Program; therefore, the applicant's proposal complies with the current staff position. The staff's concern described in RAI 3.3.2.2
| |
| -1 is resolved.
| |
| The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -80, the staff finds the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program acceptable. This program conducts inspections during periodic system surveillances or maintenance activities when internal surfaces accessible and monitors parameters such as corrosion, corrosion byproducts, coating degradation, scale/deposits, pits, and surface discoloration and discontinuities. In addition, the staff finds that the use of Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is acceptable to manage these components exposed to raw water because the raw water is associated with the boron recovery and waste processing liquid and waste processing liquid systems and not the open
| |
| -cycle cooling system. Therefore, the use of this program is consistent with the current staff position.
| |
| In its response dated February 3, 2011, with regard to RAI 3.5.2.5
| |
| -2, the applicant stated that the raw water in the sumps is not part of the open
| |
| -cycle cooling water system and receives no Aging Management Review Results 3-397 chemical addition. The applicant also stated that the sumps are normally dry or slightly wetted and, if water enters the lined or unlined sumps, the sump pump removes the water. The applicant further stated that because the sumps can be wetted, it was assumed that they are in a raw water environment, that the Structures Monitoring Program will perform an inspection for degradation, and that any degradation identified will be appropriately dispositioned. The staff finds the applicant's response acceptable because the sumps are typically not wet, and the applicant conservatively assigned a raw water environment. In addition, the staff finds the response acceptable because the GALL Report, Revision 2, allows components exposed to raw water, that are not part of the open
| |
| -cycle cooling water system, to be managed with programs that periodically inspect the components. The staff notes that the Structures Monitoring Program will conduct periodic visual inspections that are consistent with the current staff position in GALL Report, Revision 2. The staff's concern described in RAI 3.5.2.5
| |
| -2 is resolved.
| |
| The staff's evaluation of the applicant's Structures Monitoring Program is documented in SER Section 3.0.3.2.18. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -80, the staff finds the applicant's proposal to manage aging using the Structures Monitoring Program acceptable because the program conducts periodic visual inspections for aging effects specific to each structure by qualified individuals. In addition, the staff finds that the use of Structures Monitoring Program is acceptable to manage these components exposed to raw water because the raw water is not the open
| |
| -cycle system; therefore, the use of this program is consistent with the current staff position in the GALL Report, Revision 2.
| |
| The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.1.16 Loss of Material Due to Pitting, Crevice, and Microbiologically
| |
| -Influenced Corrosion, and Fouling LRA Table 3.3.1, item 3.3.1
| |
| -81, addresses copper piping, piping components, and piping elements exposed to raw water, which are being managed for loss of material due to pitting and crevice corrosion, MIC, and fouling. The applicant credits the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage the aging effect. The GALL Report recommends GALL Report AMP XI.M20, "Open
| |
| -Cycle Cooling Water System," to ensure that these aging effects are adequately managed. The associated AMR items cite generic Note E indicating that the AMR item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited.
| |
| GALL Report AMP XI.M20 recommends using condition and performance monitoring programs to manage the aging of these items. In addition, GALL Report AMP XI.M20 recommends using chemical treatments whenever the potential for biological fouling species exists and also recommends the use of periodic flushing. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -81, for which the applicant cited generic Note E, the staff noted that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program proposes to manage the aging of copper piping, piping components, and piping elements through the use of periodic inspection on the internal surfaces of components. It was not clear to the staff how the opportunistic visual inspections will be able to manage aging of components in a raw water system that does not include chemical treatments or surveillances. By letter dated January 5, 2011, the staff issued RAI 3.3.2.2
| |
| -1, requesting that the applicant justify the Aging Management Review Results 3-398 use of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, which is only a visual inspection program, to manage aging in the raw water environment.
| |
| In its response dated February 3, 2011, the applicant stated that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program was chosen because the internal raw water environments are not covered by any other AMP. The applicant also stated that its conclusion to use this AMP is supported by information in Revision 2 to the GALL Report, that this program applies to components exposed to any water systems not included in the open-cycle cooling water, closed treated water, or fire water AMPs. The applicant further stated that its equipment inspections have been successful at identifying and resolving corrosion or degradation before it affects the ability of the component to perform its intended function. The staff finds the applicant's response acceptable because the GALL Report, Revision 2, allows components exposed to raw water, that are not part of the open
| |
| -cycle cooling water system, to be managed with the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Component Program; therefore, the applicant's proposal complies with the current staff position. The staff's concern described in RAI 3.3.2.2
| |
| -1 is resolved.
| |
| The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -81, the staff finds the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program acceptable. This program conducts visual inspections during periodic system surveillances or maintenance activities when internal surfaces are accessible and monitors parameters such as corrosion, corrosion byproducts, coating degradation, scale/deposits, pits, and surface discoloration and discontinuities. In addition, the staff finds that the use of Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is acceptable to manage these components exposed to raw water because the raw water is associated with the chlorination, dewatering, plant floor drain, and screen wash systems and not the open
| |
| -cycle cooling system. Therefore, the use of this program is consistent with the current staff position in the GALL Report, Revision 2.
| |
| The staff noted that, in a letter dated November 15, 2010, the applicant submitted Supplement 2 to the LRA. In this supplement, LRA Table 3.3.1, item 3.3.1
| |
| -81, was modified to include the Buried Piping and Tanks Inspection Program for copper
| |
| -alloy components. The staff also noted that LRA Table 3.3.2
| |
| -37 identifies the specific components as copper alloy greater than 15
| |
| -percent zinc valve bodies that are inside a vault and exposed to raw water due to groundwater inleakage as stated in plant
| |
| -specific Note 9. The staff further noted that, given that the valves are constructed of copper alloy greater than 15
| |
| -percent zinc, they would also be susceptible to selective leaching. The staff noted that, in Table 3.3.2
| |
| -37, the applicant established an item for these components that identifies selective leaching as an AERM and uses the Selective Leaching Program to manage this aging effect. The staff finds that the applicant is appropriately managing the added components because they are managing aging due loss of material and selective leaching.
| |
| For the copper alloy greater than 15
| |
| -percent zinc valve body items associated with generic Note E, GALL Report AMP XI.M.20 recommends using coatings to protect the metal surfaces from being exposed to aggressive environments and visual inspections to manage the aging of these items. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -81 for which the Aging Management Review Results 3-399 applicant cited generic Note E, the staff noted that the Buried Piping and Tanks Inspection Program proposes to manage the aging of piping, piping components, and piping elements through the use of coatings to protect the metal surfaces from being exposed to aggressive environments and visual inspections.
| |
| The staff's evaluation of the applicant's Buried Piping and Tanks Inspection Program is documented in SER Section 3.0.3.3.1. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -81, the staff finds the applicant's proposal to manage aging using the Buried Piping and Tanks Inspection Program acceptable for the following reasons:
| |
| * The program includes preventive actions such as external coatings and wrappings installed to industry standard practices.
| |
| * Periodic visual inspections will be performed starting 10 years prior to the period of extended operation and extend into both 10
| |
| -year periods during the period of extended operation to ensure that coatings remain intact.
| |
| * Plant-specific operating experience will be used to inform inspection locations.
| |
| The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.1.17 Reduction of Heat Transfer Due to Fouling LRA Table 3.3.1, item 3.3.1
| |
| -83, addresses stainless steel and copper
| |
| -alloy heat exchanger tubes exposed to raw water, which are being managed for reduction of heat transfer due to fouling. The applicant credits the Fire Water System Program to manage the aging effect. The GALL Report recommends GALL Report AMP XI.M20, "Open
| |
| -Cycle Cooling Water System," to ensure that these aging effects are adequately managed. The associated AMR items cite generic Note E indicating that the AMR item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited.
| |
| GALL Report AMP XI.M20 recommends using condition and performance monitoring programs to manage the aging of these items. In addition, the GALL Report AMP XI.M20 program recommends using chemical treatments whenever the potential for biological fouling species exists and also recommends the use of periodic flushing. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -83, for which the applicant cited generic Note E, the staff noted that the Fire Water System Program proposes to manage the aging of stainless steel and copp er-alloy heat exchanger tubes through the use of inspections, periodic flushing, system performance testing, and chemical additions to prevent microbiological growth.
| |
| The staff's evaluation of the applicant's Fire Water System Program is documented in SER Section 3.0.3.2.8. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -83, the staff finds the applicant's proposal to manage aging using the Fire Water System Program acceptable because the program conducts inspections roughly every outage and uses preventive actions including chemical additions and performance verification.
| |
| The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained Aging Management Review Results 3-400 consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.1.18 Loss of Material and Flow Blockage Due to Fouling During the review, the staff noted that the applicant added several AMR items to LRA Table 3.3.2-15 without citing a Table 1 item. These AMR items consist of steel, gray cast iron, galvanized steel, stainless steel, aluminum, copper alloy, and copper alloy greater than 15
| |
| -percent zinc piping, piping components, pump casings, vortex plates, and heat exchanger components in the fire water protection system exposed internally to uncontrolled indoor air, condensation, and raw water and being managed by the Fire Water System Program for loss of material and flow blockage due to fouling. The applicant cites generic Note A and plant
| |
| -specific Note 6, which states, "[c]onsistent with NUREG
| |
| -1801 as modified by LR
| |
| -ISG-2012-02." The staff finds the applicant's use of the Fire Water System Program to manage aging of these components acceptable because the program includes periodic internal visual examinations and flow testing that are capable of detecting loss of material and fouling due to flow blockage.
| |
| 3.3.2.1.19 Loss of Material and Cracking Due to Corrosion Under Insulation By letter dated March 5, 2014, the applicant provided changes in response to LR
| |
| -ISG-2012-02. The applicant identified that the auxiliary systems include the following types of insulated components: (a) indoor, insulated steel piping and fittings exposed to an external condensation environment, (b) outdoor, insulated steel piping and fittings that are exposed to an external outdoor air environment, (c) indoor, insulated copper alloy piping and fittings that are exposed to an external condensation environment, (d) indoor, insulated stainless steel piping and fittings that are exposed to an external condensation environment. The applicant also amended AMR Tables 3.3.2
| |
| -9, 3.3.2-10, 3.3.2-12, 3.3.2-15, 3.3.2-27, 3.3.2-28, 3.3.2-29, and 3.3.2
| |
| -37 to include the AMR items for insulated components that were consistent with those provided for insulated components in LR
| |
| -ISG-2012-02 in regard to corrosion under insulation.
| |
| In these AMR items, the applicant identified that the External Surfaces Monitoring Program will be used to manage loss of material or cracking that might occur as a result of corrosion under insulation. The staff evaluates the ability of the External Surfaces Monitoring Program to manage loss of material and cracking in insulated piping and fittings in SER Section 3.0.3.2.14.
| |
| The staff noted in its letter of March 5, 2014, that the applicant amended LRA Table 2.3.3
| |
| -4 for the chlorination system to include "Insulated Piping and Fittings" as an additional within
| |
| -scope component type for the system. However, the staff noted that the applicant did not amend LRA Table 3.3.2
| |
| -4, "Summary of Aging Management Evaluation
| |
| -Chlorination System," to include applicable AMR items of cracking or loss of material for insulated components in the system. By letter dated November 18, 2014, the staff issued RAI B.2.1.11
| |
| -3, requesting that the applicant provide its basis for not amending LRA Table 3.3.2
| |
| -4 to include applicable AMR items for insulated piping and fittings.
| |
| The applicant responded to RAI B.2.1.11
| |
| -3, by letter dated March 9, 2015, and stated that the chlorination system does not include any insulated components that would need to be managed for the aging effect of loss of material due to corrosion under insulation. The applicant stated that Enclosure 1, Section H, of its response dated March 5, 2014, inadvertently listed the chlorination system as containing these types of components. The applicant amended the LRA to delete any prior reference that identified that insulated components were included in the Aging Management Review Results 3-401 chlorination system. The staff finds the applicant's response acceptable because the inconsistency in the LRA was an editorial error. The staff's concern described in RAI B.2.1.11
| |
| -3 is resolved.
| |
| The staff finds the applicant's proposal to manage corrosion under insulation with the External Surfaces Monitoring Program acceptable because the periodic visual inspections are capable of detecting aging effects.
| |
| The staff concludes that the applicant demonstrated that the effects of aging for these components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.2 Aging Management Review Results Consistent with the GALL Report for Which Further Evaluation is Recommended In LRA Section 3.3.2.2, the applicant further evaluates aging management, as recommended by the GALL Report, for the auxiliary system components and provides information concerning how it will manage the following aging effects:
| |
| * cumulative fatigue damage
| |
| * reduction of heat transfer due to fouling
| |
| * cracking due to SCC
| |
| * cracking due to SCC and cyclic loading
| |
| * hardening and loss of strength due to elastomer degradation
| |
| * reduction of neutron
| |
| -absorbing capacity and loss of material due to general corrosion
| |
| * loss of material due to general, pitting, and crevice corrosion
| |
| * loss of material due to general, pitting, crevice, and MIC
| |
| * loss of material due to general, pitting, crevice, MIC, and fouling
| |
| * loss of material due to pitting and crevice corrosion
| |
| * loss of material due to pitting, crevice, and galvanic corrosion
| |
| * loss of material due to pitting, crevice, and MIC
| |
| * loss of material due to wear
| |
| * loss of material due to cladding breach
| |
| * QA for aging management of nonsafety
| |
| -related components For component groups evaluated in the GALL Report, for which the applicant claimed consistency with the report and for which the report recommends further evaluation, the staff audited and reviewed the applicant's evaluation to determine if it adequately addressed the issues further evaluated. In addition, the staff reviewed the applicant's further evaluations against the criteria contained in SRP
| |
| -LR Section 3.3.2.2. The staff's review of the applicant's further evaluation follows.
| |
| 3.3.2.2.1 Cumulative Fatigue Damage LRA Section 3.3.2.2.1 states that fatigue is a TLAA, as defined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3 documents the staff's review of the applicant's evaluation of this TLAA.
| |
| | |
| Aging Management Review Results 3-402 LRA Section 3.3.2.2.1, which is associated with LRA Table 3.3.1, items 3.3.1
| |
| -1 and 3.3.1
| |
| -2, addresses how steel cranes structural girders exposed to air
| |
| -indoor uncontrolled (external), and steel and stainless steel piping, piping components, piping elements, and heat exchanger components exposed to air
| |
| -indoor uncontrolled, treated borated water or treated water are being managed for cumulative fatigue damage. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that fatigue is a TLAA, as defined in 10 CFR 54.3, and is required to be evaluated in accordance with 10 CFR 54.21(c). The applicant stated that TLAAs identified for fatigue in the chemical and volume control system (CVCS) are discussed in LRA Section 4.3, and the evaluation of crane load cycles as a TLAA for cranes is discussed in LRA Section 4.7.6.
| |
| The staff reviewed LRA Section 3.3.2.2.1 against the criteria in SRP
| |
| -LR Section 3.3.2.2.1, which states that fatigue of these auxiliary system components is a TLAA, as defined in 10 CFR 54.3. These TLAAs are to be evaluated in accordance with the TLAA acceptance criteria requirements in 10 CFR 54.21(c)(1) and in accordance with SRP
| |
| -LR Section 4.3, "Metal Fatigue Analysis," or SRP
| |
| -LR Section 4.7, "Other Plant
| |
| -Specific Time
| |
| -Limited Aging Analyses." The staff reviewed the applicant's AMR items and finds that the AMR results are consistent with the recommendations of the GALL Report and SRP
| |
| -LR for managing cumulative fatigue damage in steel cranes, structural girders exposed to air
| |
| -indoor uncontrolled (external), and steel and stainless steel piping, piping components, piping elements, and heat exchanger components exposed to air
| |
| -indoor uncontrolled, treated borated water or treated water, except as identified below. In its review of LRA Table 3.3.2
| |
| -3, the staff noted that, in addition to the AMR items associated with item 3.3.1
| |
| -2, the applicant also included two AMR items associated with item 3.1.1
| |
| -8 regarding TLAAs of valve body (Class 1) and piping and fittings (Class 1 less than 4 in.). LRA Section 4.3.7 states that the CVCS components were designed in accordance with ASME Code Section III Class 2 and Class 3 requirements. It is not clear to the staff which piping and fittings are represented in LRA Table 3.3.2
| |
| -3 and whether the two AMR items (3.1.1
| |
| -8) represent the portion of the CVCS that is located inside the reactor containment. By letter dated January 21, 2010, the staff issued RAI 3.3.2.2.1
| |
| -2, asking the applicant to clarify which portions of the CVCS system are represented by AMR items 3.1.1
| |
| -8 in LRA Table 3.3.2
| |
| -3 for the CVCS. The staff also asked the applicant to clarify the inconsistency between LRA Section 4.3.7, which stated that the CVCS components were designed to ASME Code Section III Class 2 and Class 3 requirements, and LRA Table 3.1.1, item 3.1.1
| |
| -8, which represents Class 1 components. Furthermore, the staff requested that the applicant identify the TLAA in LRA Section 4 that represents the fatigue analysis for these Class 1 components.
| |
| In its response dated February 18, 2011, the applicant clarified that item 3.1.1
| |
| -8 represents the Class 1 RCPB components in the CVCS (LRA Table 3.3.2
| |
| -3) system. The applicant also stated that item 3.3.1
| |
| -2, which represents the Class 2 and Class 3 components in the CVCS, were already included in LRA Table 3.3.2
| |
| -3, and no changes were necessary. The applicant stated that the Class 1 RCPB components in the CVCS are part of the NSSS and are evaluated in LRA Sections 4.3.1 and 4.3.2. The applicant also stated that the TLAAs for Class 2 and Class 3 components are evaluated in LRA Section 4.3.7.
| |
| Based on its review, the staff finds the applicant's response to RAI 3.3.2.2.1
| |
| -2 acceptable because the applicant clarified the AMR items and associated TLAAs for Class 1 RCP B components and Class 2 and Class 3 components in the CVCS, and the applicant's AMR Aging Management Review Results 3-403 results are consistent with the recommendations of the GALL Report. The staff's review of the applicant's TLAAs associated with the Class 1 components and Class 2 and Class 3 components are documented in SER Section 4.3. The staff's concern described in RAI 3.3.2.2.1-2 is resolved.
| |
| The staff noted that LRA Table 3.5.2
| |
| -3 does not include any applicable items for management of cumulative fatigue damage in the steel cranes structural girders even though LRA Section 4.7.6 discusses the TLAA associated with crane load cycle limits. By letter dated January 21, 2010, the staff issued RAI 3.3.2.2.1
| |
| -1, Request 2, asking the applicant to include in LRA Table 3.5.2
| |
| -3 the applicable items for management of cumulative fatigue damage in the steel cranes structural girders or provide the basis for excluding these items from the LRA.
| |
| In its response dated February 18, 2011, the applicant amended LRA Table 3.5.2
| |
| -3 to include the associated AMR items for the steel crane structural girders for fuel handling and overhead cranes, consistent with GALL Report AMR item VII.B
| |
| -2. The applicant stated that two rows representing TLAAs of steel structural support for 1
| |
| -FH-RE-1 spent fuel cask handling crane and 1-MM-CR-3 polar gantry crane exposed to air
| |
| -indoor uncontrolled have been added to LRA Table 3.5.2
| |
| -3. Based on its review of the amended LRA Table 3.5.2
| |
| -3, the staff finds the applicant's response to RAI 3.3.2.2.1
| |
| -1, Request 2, and the additions of the AMR items acceptable because they are consistent with GALL AMR item VII.B
| |
| -2 for the steel cranes structural girders. The staff's concern described in RAI 3.3.2.2.1
| |
| -1, Request 2, is resolved.
| |
| Based on the staff's review, it concludes that the applicant met the SRP
| |
| -LR Section 3.3.2.2.1 criteria. For those items that apply to LRA Section 3.3.2.2.1, the staff determined that the LRA is consistent with the GALL Report and that the applicant 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). SER Sections 4.3 and 4.7 document the staff's review of the applicant's evaluation of the TLAAs for these components.
| |
| 3.3.2.2.2 Reduction of Heat Transfer due to Fouling LRA Section 3.3.2.2.2 is associated with LRA Table 3.3.1, item 3.3.1
| |
| -3, and addresses stainless steel heat exchanger tubes exposed to treated water. The applicant stated that this item is not applicable because this item is associated with the GALL Report item VII.E3
| |
| -6, which applies to BWR reactor water cleanup system heat exchangers. The staff noted that the related item, AP
| |
| -62, from SRP
| |
| -LR Table 3.3.1, was derived from a previous SER for heat exchanger tubes exposed to treated borated water in a spent fuel pool system. Based on this, the applicant's determination that this item was not applicable did not appear appropriate. By letter dated February 24, 2011, the staff issued RAI 3.3.2.2.2
| |
| -1, requesting that the applicant provide additional bases regarding the non
| |
| -applicability of this item and the bases for not managing reduction of heat transfer for heat exchanger tubes identified as having a heat transfer function.
| |
| In its response dated March 22, 2011, the applicant stated that the "treated borated water" environment is different from the "treated water" environment. The applicant provided the definitions of treated water and treated boated water from the GALL Report Section IX.D, which states that, unlike the PWR reactor coolant environment (treated borated water), the BWR reactor coolant environment (treated water) does not contain boron, a recognized corrosion Aging Management Review Results 3-404 inhibitor. The applicant also referred to GALL Report Section IX.F, which describes fouling as an accumulation of deposits that may be due to particulate fouling, such as sediment, silt or corrosion products. The applicant further stated that none of the heat exchanger tubes in LRA Section 3.3 are exposed to treated water; however, there are stainless steel heat exchanger tubes exposed to treated borated water in the auxiliary systems. The applicant provided the following basis for its determination that these components are not susceptible to reduction of heat transfer: Seabrook's determination that reduction of heat transfer is not an aging effect in treated borated water environment is based on plant and industry operating experience. Seabrook is not aware of any fouling in treated borated water environment leading to reduction of heat transfer in stainless steel heat exchanger tubes. This conclusion is consistent with NUREG
| |
| -1801, Revision 1. NUREG
| |
| -1801, Revision 1, does not identify reduction of heat transfer as an aging effect for stainless steel heat exchanger tubes in treated borated water environment.
| |
| Fouling of the stainless steel heat exchanger tubes on the treated borated water side would only occur through the buildup of corrosion products. Since Seabrook's treated borated water contains boron, a corrosion inhibitor, corrosion product buildup resulting in reduction of heat transfer in treated borated water environment is not a credible aging effect/mechanism. This is further validated by NUREG
| |
| -1801, Revision 1, items V.A
| |
| -27 and V.D1-30 (NUREG-1800, Table 3.2-1, items 48 and 49), which state that Water Chemistry Program alone (for PWR primary water) is adequate for managing loss of material in stainless steel components exposed to treated borated water, indicating that corrosion is not expected to occur in stainless steel components exposed to treated borated water. In the absence of corrosion, corrosion product buildup will not occur.
| |
| The applicant also stated that since reduction of heat transfer in treated borated water is not identified as a potential aging effect, no items for reduction of heat transfer in treated borated water appear in the LRA. The applicant further stated that its conclusion is consistent with NUREG
| |
| -1801, Revision 1 and Revision 2, as well as the staff conclusions, as stated in the Beaver Valley (Section 3.2.2.3.2) and Prairie Island (Section 3.2.2.2.4) final SERs.
| |
| The staff reviewed the applicant response and the cited portions of the GALL Report. The staff noted that, although the GALL Report, Revision 1, states that boron is a recognized corrosion inhibitor, the GALL Report, Revision 2, deleted that discussion from the definition of treated water. The staff also reviewed the AMR items V.A
| |
| -27 and V.D1
| |
| -30 (SRP-LR, Table 3.2, item 49) and noted that the GALL Report credits water chemistry to manage loss of material due to pitting and crevice corrosion in stainless components exposed to treated borated water. The staff noted that, although the basis for adding these items in the GALL Report, Revision 1, stated that a significant loss of material was not expected, the potential for corrosion and consequently corrosion product buildup still exists. The staff also reviewed the Beaver Valley and Prairie Island SERs, and the associated LRAs cited by the applicant, and noted that both LRAs identified reduction of heat transfer for stainless steel heat exchanger tubes in a treated borated water environment as an aging effect requiring managing. Based on the above, by letter dated May 23, 2011, the staff issued RAI 3.2.2.2.4.2
| |
| -1A, requesting that the applicant justify why heat exchanger tubes, which have a heat transfer intended function, do not need to include a reduction of heat transfer aging effect requiring management. In addition, the RAI asked the applicant to provide the pla nt-specific and industry operating experience cited in its Aging Management Review Results 3-405 response demonstrating that reduction in heat transfer was not a credible aging effect for the components in question.
| |
| In its response dated June 2, 2011, the applicant revised LRA Tables 3.3.2
| |
| -3 and 3.3.2-39 to include AMR items for stainless steel heat exchanger components in treated borated water environment that are being managed for reduction of heat transfer by the Water Chemistry Program. The AMR items cite generic Note H and plant
| |
| -specific notes, which state that reduction of heat transfer due to fouling is not in the GALL Report for this component, material, and environment combination.
| |
| The staff was unable to find the applicant's response acceptable because the guidance in the SRP-LR and GALL Report was revised in LR
| |
| -ISG-2011-01, "Aging Management of Stainless Steel Structures and Components in Treated Borated Water," to add the One
| |
| -Time Inspection Program to verify the effectiveness of the Water Chemistry Program to manage stainless steel components for loss of material, cracking, and reduction of heat transfer in treated borated water environments that are not controlled to low oxygen levels. The staff noted that, prior to the issuance of LR
| |
| -ISG-2011-01, the SRP
| |
| -LR and GALL Report guidance inappropriately credited the boron in borated water as a corrosion inhibitor in place of other aging management activities.
| |
| Therefore, by letter dated May 29, 2012, the staff issued RAI 3.2.1.48
| |
| -1, requesting that the applicant describe how the effectiveness of the Water Chemistry Program to manage reduction of heat transfer will be verified for stainless steel components exposed to treated borated water with greater than 5 ppb oxygen. This issue was identified as Open Item OI 3.2.2.1
| |
| -1. In its response dated June 19, 2012, the applicant revised the LRA to add reduction of heat transfer as an aging effect for several stainless steel heat exchangers exposed to treated borated water and to manage this aging effect with the Water Chemistry and One-Time Inspection Programs. The applicant also revised LRA Table 3.3.1, item 3.3.1
| |
| -3, to state that this item is now applicable to Seabrook. The staff finds the applicant's response acceptable because the effectiveness of the Water Chemistry Program will be verified by the applicant to ensure that potential fouling does not lead to loss of intended function during the period of extended operation. In addition, the staff evaluated the adequacy of the applicant's Water Chemistry and One
| |
| -Time Inspection Programs, documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. In its review of components associated with item 3.3.1
| |
| -3, the staff finds the applicant's proposal to manage aging using the Water Chemistry and One
| |
| -Time Inspection Programs acceptable, because the Water Chemistry Program establishes the plant water chemistry control parameters and their limits to mitigate aging and identifies the actions required if the parameters exceed the limits, and the One
| |
| -Time Inspection Program prescribes appropriate visual or other inspection techniques capable of detecting fouling prior to loss of intended function, consistent with the revised GALL Report guidance in LR
| |
| -ISG-2011-01. Based on its review, 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). The staff's concern regarding reduction of heat transfer of heat exchanger tubes in auxiliary systems and described in RAI 3.2.1.48
| |
| -1 is resolved.
| |
| 3.3.2.2.3 Cracking Due to Stress Corrosion Cracking
| |
| | |
| Aging Management Review Results 3-406 The staff reviewed LRA Section 3.3.2.2.3 against the following criteria in SR P-LR Section 3.3.2.2.3:
| |
| (1) SRP-LR Section 3.3.2.2.3 states that cracking due to SCC could occur in the stainless steel piping, piping components, and piping elements of the BWR standby liquid control system that are exposed to sodium pentaborate solution greater than 140 °F (60 °C).
| |
| LRA Section 3.3.2.2.3.1, associated with LRA Table 3.3.1, item 3.3.1
| |
| -4, addresses cracking due to SCC in stainless steel piping, piping components, and piping elements exposed to sodium pentaborate at greater than 140 °F (60 °C).
| |
| The applicant stated that this item is not applicable because this aging issue is only applicable to BWRs. The staff reviewed SRP
| |
| -LR and confirmed that this aging effect is only applicable to the standby liquid control system, which is only associated with BWRs; therefore, it finds the applicant's determination acceptable.
| |
| (2) LRA Section 3.3.2.2.3.2, is associated with LRA Table 3.3.1, item 3.3.1
| |
| -5, and addresses stainless steel and stainless clad steel heat exchanger components exposed to treated water greater than 140 °F (60 °C). The applicant stated that this item is not applicable because this item is associated with GALL Report, items VII.E3
| |
| -3 and VII.E3
| |
| -19, which apply to BWR reactor water cleanup system heat exchangers. The staff reviewed LRA Section 3.3 and noted that, although there were no in
| |
| -scope stainless steel heat exchanger tubes exposed to treated water greater than 140 °F (60 °C) present in the auxiliary systems, there were several systems with heat exchanger tubes exposed to treated borated water greater than 140 °F (60 °C). As a result, the staff considered this aging effect to be applicable to these components. However, the staff also noted that the applicant aligned these components with item 3.3.1
| |
| -7, which is associated with non
| |
| -regenerative heat exchanger tubes and cited generic Note E indicating that a different AMP or plant
| |
| -specific AMP was credited to manage this aging effect. The staff further noted that the applicant also cited plant
| |
| -specific Note 7 for these components, which stated that the Water Chemistry and One
| |
| -Time Inspection Programs were used to manage this aging effect. The staff finds the applicant's determination, that item 3.3.1
| |
| -5 is not applicable, acceptable because the applicant aligned the applicable components with item 3.3.1
| |
| -7, which has comparable acceptance criteria as item 3.3.1
| |
| -5; consequently, it will adequately manage this aging effect.
| |
| (3) LRA Section 3.3.2.2.3.3 is associated with LRA Table 3.3.1, item 3.3.1
| |
| -6, and addresses stainless steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust, which are being managed for cracking due to SCC by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The criteria in SRP
| |
| -LR Section 3.3.2.2.3, item 3, state that cracking due to SCC could occur for stainless steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust. The SRP
| |
| -LR states that a plant
| |
| -specific AMP should be used. The SRP
| |
| -LR also states that acceptance criteria for the plant
| |
| -specific AMP will include a description of its basis and analysis methodology, ensure continued functional operation of structure and components, contain quantified criteria or a illustrate method of quantification, and discuss qualitative inspections via ASME or site-specific criteria. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that it will implement the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage cracking due to SCC for the Aging Management Review Results 3-407 stainless steel diesel exhaust piping components exposed to diesel exhaust in the diesel generator system and fire protection system.
| |
| The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff noted that the AMP includes visual surface, magnification, and ultrasonic inspection methods. The staff also noted that the reports will be evaluated by a system engineer who will help ensure the extent and schedule of inspections to detect degradation prior to loss of function, and these reviews will include trending to determine whether the number of locations and intervals are providing aging management consistent with the CLB. Acceptance criteria for various corrosion mechanisms will be identified in appropriate inspection procedures. The staff further noted that GALL Report AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," states that inspections are performed when the internal surfaces are accessible during the performance of periodic surveillances and during maintenance activities or during scheduled outages. It also states that inspection intervals are established such that they provide timely detection of degradation. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -6, the staff finds that the applicant has met the further evaluation criteria, and the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is acceptable for the following reasons:
| |
| * The applicant will perform sufficient inspections for each material
| |
| -environment combination to provide an overall assessment of any aging degradation that may be occurring.
| |
| * The selection of inspections will consider materials, operating environments, industry and plant
| |
| -specific operating experience, engineering evaluations of equipment performance, and susceptibility to aging due to time in service, severity of operating conditions, and lowest design margins.
| |
| * Recurring surveillance and maintenance activities provides the ability to detect aging of the material
| |
| -environment combination prior to loss of function.
| |
| * Inspection results will be trended.
| |
| Based on the program identified, the staff concludes that the applicant's program meets SRP-LR Section 3.3.2.2.3, item 3, criteria. For those items that apply to LRA Section 3.3.2.2.3.3, the staff determined that the LRA is consistent with the GALL Report and that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.2.4 Cracking Due to Stress Corrosion Cracking and Cyclic Loading The staff reviewed LRA Section 3.3.2.2.4 against the following criteria in SRP
| |
| -LR Section 3.3.2.2.4:
| |
| (1) LRA Section 3.3.2.2.4.1, is associated with LRA Table 3.3.1, item 3.3.1
| |
| -7, and addresses cracking due to SCC and cyclic loading in stainless steel non
| |
| -regenerative Aging Management Review Results 3-408 heat exchanger components exposed to treated borated water greater than 140 °F (60 °C), which are being managed by the Water Chemistry and the One
| |
| -Time Inspection Programs. The criteria in SRP
| |
| -LR Section 3.3.2.2.4, item 1, states that the existing AMP monitors and controls primary water chemistry to manage cracking due to SCC; however, control of water chemistry does not preclude cracking due to SCC and cyclic loading. The SRP
| |
| -LR also states that the effectiveness of Water Chemistry Control Programs should be confirmed using a plant
| |
| -specific AMP, and an acceptable verification program includes temperature and radioactivity monitoring of the shell side water and eddy current testing of the tubes. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that the Water Chemistry Program will manage this aging effect, and the effectiveness of the program will be confirmed by the One-Time Inspection Program.
| |
| The staff's evaluations of the applicant's Water Chemistry and the One
| |
| -Time Inspection Programs are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. The staff reviewed the applicant's Water Chemistry Program and noted that it controls detrimental contaminants below the levels known to cause cracking. The staff also noted that the applicant credited its One
| |
| -Time Inspection Program to verify the effectiveness of the Water Chemistry Program to manage this aging effect. However, it is not clear whether the non
| |
| -regenerative heat exchangers will be included in the sample of components to be inspected and what inspection techniques will be used. In addition, it is also not clear if temperature and radioactivity monitoring of the shell side water is performed to verify the integrity of the heat exchangers. By letter dated January 5, 2011, the staff issued RAI 3.3.2.2.4
| |
| -1, requesting that the applicant clarify if the non
| |
| -regenerative heat exchangers will be included in sample of components to be inspected, to provide the inspection method that will be used to detect cracking in the heat exchanger tubes, and to confirm if temperature and radioactivity monitoring of the shell side water is performed.
| |
| In its response dated February 3, 2011, the applicant stated that the non
| |
| -regenerative heat exchangers will be included in the sample of components to be inspected in the One-Time Inspection Program and that eddy current testing will be used to detect cracking in the stainless steel tubes. The applicant also revised LRA Section 3.3.2.2.4.1, item 1, and stated that temperature and radioactivity monitoring of the shell side water is performed to verify the integrity of the heat exchangers.
| |
| The staff finds the applicant response acceptable because the applicant is consistent with the GALL Report recommendation of verification program of eddy current testing of tubes to detect cracking and temperature and radioactivity monitoring of the shell side water to verify heat exchanger integrity. The staff's concern described in RAI 3.3.2.2.4
| |
| -1 is resolved.
| |
| Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.2.2.2.4, item 1, criteria. For those items that apply to LRA Section 3.2.2.2.4.1, the staff determined that the LRA is consistent with the GALL Report. The staff also determined that the applicant 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).
| |
| | |
| Aging Management Review Results 3-409 (2) LRA Section 3.3.2.2.4.2, is associated with LRA Table 3.3.1, item 3.3.1
| |
| -8, and addresses cracking due to SCC and cyclic loading in stainless steel regenerative heat exchanger components exposed to treated borated water greater than 140 °F (60 °C). The criteria in SRP
| |
| -LR Section 3.3.2.2.4, item 2, states that cracking due to SCC and cyclic loading may occur in stainless steel regenerative heat exchanger components exposed to treated borated water greater than 140 °F (60 °C). The SRP
| |
| -LR also states that the existing AMP monitors and controls primary water chemistry to manage cracking due to SCC; however, these controls do not preclude cracking and recommend that the effectiveness of Water Chemistry Control Program be confirmed using a plant
| |
| -specific AMP. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that this aging effect will be managed by the Water Chemistry Program. The applicant also stated that, since the regenerative heat exchanger is welded and cannot be disassembled for internal inspection, the effectiveness of the water chemistry controls will be confirmed by a one
| |
| -time inspection of a non
| |
| -regenerative heat exchanger with the same material and environment combination in the chemical and volume control system. The applicant further stated that the integrity of the regenerative heat exchanger is confirmed by continuous temperature monitoring.
| |
| SRP-LR Section 3.3.2.2.4 states that cracking due to SCC and cyclic loading may occur in stainless steel PWR regenerative heat exchanger components exposed to treated borated water greater than 140 °F (60 °C). The existing AMP monitors and controls primary water chemistry in PWRs to manage the aging effects of cracking due to SCC. However, control of water chemistry does not preclude cracking due to SCC and cyclic loading; therefore, the effectiveness of Water Chemistry Control Programs should be confirmed to ensure that cracking does not occur. The GALL Report recommends that a plant-specific AMP be evaluated to verify the absence of cracking due to SCC and cyclic loading to ensure that these aging effects are adequately managed.
| |
| The staff's evaluations of the applicant's Water Chemistry and the One
| |
| -Time Inspection Programs are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. In its review of components associated with item 3.3.1
| |
| -8, the staff finds that the applicant met the further evaluation criteria. The staff also found that the applicant's proposal to manage aging using the specified programs is acceptable because the Water Chemistry Program includes control of detrimental contaminants below the levels known to cause cracking. Additionally, the one
| |
| -time inspection of the non
| |
| -regenerative heat exchanger will verify the effectiveness of the Water Chemistry Program and confirm that cracking in not occurring in comparable components in the same environment.
| |
| Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.2.2.2.4, item 2, criteria. For those items that apply to LRA Section 3.2.2.2.4.2, the staff determined that the LRA is consistent with the GALL Report. The staff also determined that the applicant 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) LRA Section 3.3.2.2.4.3, associated with LRA Table 3.3.1, item 3.3.1
| |
| -9, addresses stainless steel high
| |
| -pressure pump casings, exposed to treated borated water in the chemical and volume control system, which are being managed for cracking due to SCC Aging Management Review Results 3-410 and cyclic loading by the Water Chemistry Program and the One
| |
| -Time Inspection Program. The criteria in SRP
| |
| -LR Section 3.3.2.2.4, item 3, states that cracking due to SCC and cyclic loading could occur for stainless steel pump casings for the PWR hi gh-pressure pumps in the chemical and volume control system. The SRP
| |
| -LR also states that the GALL Report recommends the existing AMP, including monitoring and control of primary water chemistry. The SRP
| |
| -LR further recommends that this aging issue be managed by a plant
| |
| -specific program to verify the effectiveness of the Water Chemistry Control Program. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that the Water Chemistry Program effectiveness will be confirmed by the On e-Time Inspection Program.
| |
| The staff's evaluations of the applicant's Water Chemistry Program and the One
| |
| -Time Inspection Program are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. In its review of components associated with item 3.3.1
| |
| -9, the staff finds that the applicant met the further evaluation criteria, and the applicant's proposal to manage aging using the Water Chemistry Program and the One
| |
| -Time Inspection Program is acceptable because the Water Chemistry Program establishes the plant water chemistry control parameters and their limits to mitigate the environmental effect that can cause cracking and takes actions if the parameters exceed the limits. Additionally, the One
| |
| -Time Inspection Program is adequate to confirm the effectiveness of the Water Chemistry Program.
| |
| Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.4, item 3, criteria. For those items that apply to LRA Section 3.3.2.2.4.3, the staff determined that the LRA is consistent with the GALL Report and that the applicant 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).
| |
| (4) LRA Section 3.3.2.2.4.4, associated with LRA Table 3.3.1, item 3.3.1
| |
| -10, addresses cracking due to SCC and cyclic loading in high
| |
| -strength steel closure bolting exposed to air with steam or water leakage. The applicant stated that this item is not applicable because there is no high
| |
| -strength steel closure bolting exposed to air with steam or water leakage in the auxiliary system. The staff reviewed LRA Sections 2.3.3 and 3.3 and the UFSAR and confirmed that no in
| |
| -scope high
| |
| -strength steel closure bolting exposed to air with steam or water leakage are present in the auxiliary system; therefore, it finds the applicant's claim acceptable.
| |
| 3.3.2.2.5 Hardening and Loss of Strength Due to Elastomer Degradation The staff reviewed LRA Section 3.3.2.2.5 against the following criteria in SRP
| |
| -LR Section 3.3.2.2.5:
| |
| (1) LRA Section 3.3.2.2.5.1, is associated with LRA Table 3.3.1, item 3.3.1
| |
| -11, and addresses elastomer seals and components exposed to air
| |
| -indoor uncontrolled, internal or external environments, which are being managed for hardening and loss of strength due to elastomer degradation by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program for internal surfaces and the External Surfaces Monitoring Program for external surfaces. The criteria in SRP
| |
| -LR Section 3.3.2.2.5, item 1, state that hardening and loss of strength due to elastomer degradation Aging Management Review Results 3-411 may occur in elastomeric seals and components associated with auxiliary heating and ventilation systems that are exposed either internally or externally to uncontrolled indoor air. The SRP-LR recommends further evaluation of a plant
| |
| -specific AMP to ensure that these aging effects are adequately managed. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is adequate to manage the aging effects on the internal surfaces of these components, and the External Surfaces Monitoring Program is adequate to manage the aging effects on the external surfaces of these components. The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15.
| |
| The staff noted that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program provides for inspections of opportunity, performed during pre-planned, periodic system and component surveillances, or during maintenance activities when the systems are opened and the surfaces are made accessible for visual inspection. The staff also noted that for elastomeric materials, the program uses tactile techniques, which include scratching, bending, folding, stretching, and pressing in conjunction with the visual examinations.
| |
| The staff's evaluation of the applicant's Inspection of External Surfaces Monitoring Program is documented in SER Section 3.0.3.2.14. The staff noted that the External Surfaces Monitoring Program uses periodic system inspections and walkdowns to monitor for materials degradation and leakage. The staff also noted that for elastomeric materials, the program uses tactile techniques, which include scratching, bending, folding, stretching, and pressing in conjunction with the visual examinations.
| |
| In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -11, the staff finds that the applicant met the further evaluation criteria. The staff also finds that the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program and the External Surfaces Monitoring Program is acceptable because the programs use a methodology that is capable of detecting hardening and loss of strength caused by elastomer degradation before loss of intended function occurs.
| |
| Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.2.2.2.5, item 1, criteria. For those items that apply to LRA Section 3.2.2.2.5.1, the staff determined that the LRA is consistent with the GALL Report. The staff also determined that the applicant 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). (2) LRA Section 3.3.2.2.5.2, is associated with LRA Table 3.3.1, item 3.3.1
| |
| -12, and addresses elastomer lined components exposed to treated borated water in the chemical and volume control system, which are being managed for hardening and loss of strength due to elastomer degradation by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program.
| |
| | |
| Aging Management Review Results 3-412 The criteria in SRP
| |
| -LR Section 3.3.2.2.5, item 2, state that hardening and loss of strength due to elastomer degradation may occur in elastomer linings of the filters, valves, and ion exchangers in spent fuel pool cooling and cleanup systems (BWR and PWR) exposed to treated water or to treated borated water. The SRP
| |
| -LR also states that the GALL Report recommends that a plant
| |
| -specific AMP be evaluated that determines and assesses the qualified life of the elastomeric liners in the environment to ensure that these aging effects are adequately managed. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is adequate to manage the aging effects of these components.
| |
| The applicant is using LRA Table 3.3.1, item 3.3.1
| |
| -12, to address elastomer flex hoses exposed to treated borated water. The staff noted that elastomer flex hoses, when exposed to treated borated water, will have the same aging effect of hardening and loss of strength as elastomer
| |
| -lined components in the same environment. The applicant stated that for item 3.3.1
| |
| -12, the applicability is limited to the chemical and volume control system. The staff also noted that a search of the applicant's UFSAR for the spent fuel pool cooling and cleanup and chemical volume control systems confirmed that no in-scope elastomer
| |
| -lined components exposed to treated borated water are present in the spent fuel pool cooling and cleanup system.
| |
| The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15.
| |
| The staff noted that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program provides for inspections of opportunity, performed during pre-planned, periodic system and component surveillances, or during maintenance activities when the systems are opened and the surfaces are made accessible for visual inspection. The staff also noted that for elastomeric materials, the program uses tactile techniques, which include scratching, bending, folding, stretching, and pressing in conjunction with the visual examinations.
| |
| In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -12, the staff finds that the applicant met the further evaluation criteria. Additionally, the staff finds that the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is acceptable because the program uses a methodology that is capable of detecting hardening and loss of strength caused by elastomer degradation before loss of intended function occurs.
| |
| Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.2.2.2.5, item 2, criteria. For those items that apply to LRA Section 3.2.2.2.5.2, the staff determined that the LRA is consistent with the GALL Report. The staff also determined that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.2.6 Reduction of Neutron
| |
| -Absorbing Capacity and Loss of Material Due to General Corrosion
| |
| | |
| Aging Management Review Results 3-413 LRA Section 3.3.2.2.6, referenced by LRA Table 3.3.1, item 3.3.1-13, addresses Boral, boron steel spent fuel storage racks neutron
| |
| -absorbing sheets exposed to treated water or treated borated water, which are being managed for reduction of neutron
| |
| -absorbing capacity and loss of material due to general corrosion.
| |
| The applicant addressed the further evaluation criteria by stating that the Boral Monitoring Program, B.2.2.2, will be used to manage reduction of the neutron-absorbing capacity and loss of material due to general corrosion of the Boral poison sheet in the spent fuel pool, in treated water exposed to treated borated water.
| |
| The staff reviewed LRA Section 3.3.2.2.6 against the criteria in SRP
| |
| -LR Section 3.3.2.2.6, which states that reduction of neutron
| |
| -absorbing capacity and loss of material due to general corrosion could occur in the neutron
| |
| -absorbing sheets of BWR and PWR spent fuel storage racks exposed to treated water or to treated borated water. The SRP
| |
| -LR also states that the GALL Report recommends further evaluation of a plant
| |
| -specific AMP to ensure that these aging effects are adequately managed and that acceptance criteria are described in BTP RLSB
| |
| -1. The staff evaluated the applicant's Boral Monitoring Program, as documented in SER Section 3.0.3.3.3. In its review of components associated with item 3.3.1
| |
| -13, the staff finds the applicant's proposal to manage aging using the Boral Monitoring Program acceptable because the Boral Monitoring Program satisfies the acceptance criteria of the SRP
| |
| -LR and uses inspection techniques (e.g., boron areal density measurement, and visual inspections) that will detect aging effects related to the neutron absorption and dimensional integrity.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| Based on the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.6 criteria. For those items that apply to LRA Section 3.3.2.2.6, the sta ff determined that the LRA is consistent with the GALL Report, and the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.2.7 Loss of Material Due to General, Pitting, and Crevice Corrosion The staff reviewed LRA Section 3.3.2.2.7 against the following criteria in SRP
| |
| -LR Section 3.3.2.2.7:
| |
| (1) LRA Section 3.3.2.2.7.1, referenced by LRA Table 3.3.1, item 3.3.1
| |
| -14, addresses steel piping, piping components, and piping elements exposed to lubricating oil, which are being managed by the Lubricating Oil Analysis and One
| |
| -Time Inspection Programs. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that the One-Time Inspection Program will be used to verify the effectiveness of the Lubricating Oil Analysis Program to manage loss of material due to general, pitting, and crevice corrosion through examination of susceptible locations in steel tanks in the chemical and volume control, diesel generator, instrument air, and miscellaneous equipment systems.
| |
| | |
| Aging Management Review Results 3-414 The applicant further stated that the Lubricating Oil Analysis Program and the One
| |
| -Time Inspection Program will also be used to manage loss of material due to general, pitting, and crevice corrosion through examination of susceptible locations in steel piping components in the chemical and volume control system, diesel generator, fire protection, instrument air, miscellaneous equipment, and service water systems. Finally, the applicant stated that the Lubricating Oil Analysis Program and the One
| |
| -Time Inspection Program will be used to manage loss of material due to general, pitting, and crevice corrosion through examination of susceptible locations in galvanized steel piping components in the service water system.
| |
| LRA Section 3.3.2.2.7.1, referenced by LRA Table 3.3.1, item 3.3.1
| |
| -15, addresses steel reactor coolant pump oil collection system tank exposed to lubricating oil, which are being managed for loss of material due to general, pitting, and crevice corrosion by the Lubricating Oil Analysis and One
| |
| -Time Inspection Programs. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that this item was not applicable because Seabrook does not have steel containment isolation piping, piping components, crevice corrosion evaluated components, and piping elements internal surfaces exposed to lubricating oil in the oil collection for reactor coolant pumps system.
| |
| LRA Section 3.3.2.2.7.1, referenced by LRA Table 3.3.1, item 3.3.1
| |
| -16, addresses steel reactor coolant pump oil collection system and chemical and volume control system tanks exposed to lubricating oil, which are being managed for loss of material due to general, pitting, and crevice corrosion by the Lubricating Oil Analysis and One
| |
| -Time Inspection Programs. The applicant addressed the further evaluation criteria of the SRP-LR by stating that the One
| |
| -Time Inspection Program will be used to verify the effectiveness of the Lubricating Oil Analysis Program to manage for loss of material due to general, pitting, and crevice corrosion by the Lubricating Oil Analysis and One
| |
| -Time Inspection Programs. Additionally, the applicant stated that the Lubricating Oil Analysis and One-Time Inspection Programs will manage loss of material due to general, pitting, and crevice corrosion by including a one
| |
| -time thickness measurement on the bottom portion of the steel tanks exposed to lubricating oil in the oil collection for the reactor coolant pumps system.
| |
| The staff reviewed LRA Section 3.3.2.2.7.1 against the criteria in SRP
| |
| -LR Section 3.3.2.2.7, item 1, which states that loss of material due to general, pitting, and crevice corrosion could occur in steel piping, piping components, and piping elements, including the tubing, valves, and tanks in the reactor coolant pump oil collection system, exposed to lubricating oil (as part of the fire protection system). The SRP
| |
| -LR also stated that the existing AMP relies on the periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion. The SRP
| |
| -LR further states that control of lube oil contaminants may not always have been adequate to preclude corrosion; therefore, the effectiveness of lubricating oil control should be confirmed to ensure that corrosion does not occur. The SRP
| |
| -LR also states that the GALL Report recommends further evaluation of programs to manage corrosion to verify the effectiveness of the Lubricating Oil Analysis Program for which a one
| |
| -time inspection of selected components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that the component's intended function will be maintained during the period of extended operation.
| |
| | |
| Aging Management Review Results 3-415 In addition, the SRP
| |
| -LR states that corrosion may occur at locations in the reactor coolant pump oil collection tank where water from wash downs may accumulate; therefore, the effectiveness of the program should be confirmed to ensure that corrosion does not occur. The SRP
| |
| -LR also states that the GALL Report recommends further evaluation of programs to manage loss of material due to general, pitting, and crevice corrosion. This includes determining the thickness of the lower portion of the tank for which a one
| |
| -time inspection is an acceptable method to ensure that corrosion does not occur and that the component's intended function will be maintained during the period of extended operation.
| |
| The staff reviewed Table 3.3.2
| |
| -25, "Oil Collection for Reactor Coolant Pump System, Summary of Aging Management Evaluation," of the applicant's LRA and the UFSAR to verify that there is no steel reactor coolant pump oil collection system piping components exposed to lubricating oil in the oil collection for reactor coolant pumps system. Based on the information provided in Table 3.3.2
| |
| -25, the staff confirmed that the oil collection for reactor coolant pumps system only has stainless steel piping components exposed to lubricating oil. Therefore, the staff finds that item 3.3.1
| |
| -15 is not applicable.
| |
| The staff's evaluations of the applicant's Lubricating Oil Analysis and One
| |
| -Time Inspection Programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.1.8, respectively. In its review of components associated with items 3.3.1
| |
| -14 and 3.3.1
| |
| -16, the staff finds the applicant's proposal to manage the applicable aging using the One
| |
| -Time Inspection Program to verify the effectiveness of the Lubricating Oil Analysis Program acceptable. The Lubricating Oil Analysis Program was determined to be consistent with the GALL Report, and the applicant stated that the One
| |
| -Time Inspection Program will be used to examine steel piping and piping components to verify the effectiveness of the Lubricating Oil Analysis Program.
| |
| Based on the programs identified above, the staff concludes that the applicant's programs meet SRP
| |
| -LR Section 3.3.2.2.7, item 1, criteria. For those items that apply to LRA Section 3.3.2.2.7.1, the staff determined that the LRA is consistent with the GALL Report, and the applicant 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).
| |
| (2) LRA Section 3.3.2.2.7.2, associated with LRA Table 3.3.1, item 3.3.1
| |
| -17, addresses loss of material due to general, pitting, and crevice corrosion in BWR steel piping, piping components, and piping elements exposed to treated water. The applicant stated that this item is not applicable because it is only applicable to BWRs. The staff reviewed the SRP-LR and LRA Section 3.3 and noted that this item is associated only with BWRs; therefore, if finds the applicant's claim acceptable.
| |
| (3) LRA Section 3.3.2.2.7.3 is associated with LRA Table 3.3.1, item 3.3.1
| |
| -18, and addresses stainless steel and steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust, which are being managed for loss of material due to general (steel only), pitting, and crevice corrosion by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components. The criteria in SRP-LR Section 3.3.2.2.7, item 3, state that loss of material due to general (steel only), pitting, and crevice corrosion could occur for steel and stainless steel diesel exhaust piping, piping components, and piping elements exposed to diesel exhaust. The SRP
| |
| -
| |
| Aging Management Review Results 3-416 LR states that a plant
| |
| -specific AMP should be used. The SRP
| |
| -LR also states that acceptance criteria for a pla nt-specific AMP will include a description of its basis and analysis methodology, ensure continued functional operation of structure and components, contain quantified criteria or a illustrate method of quantification, and discuss qualitative inspections via ASME or site
| |
| -specific criteria. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that it will implement the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage loss of material due to general (steel only), pitting, and crevice corrosion of the steel piping components, steel silencer (diesel generator system), and stainless steel piping components exposed to diesel exhaust in the diesel generator system and fire protection system. The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff noted that the AMP includes visual surface, magnification, and ultrasonic inspection methods. The staff also noted that reports will be evaluated by a system engineer who will help ensure the extent and schedule of inspections to detect degradation prior to loss of function, and these reviews will include trending to determine whether the number of locations and intervals are providing aging management consistent with the CLB. Acceptance criteria for various corrosion mechanisms will be identified in appropriate inspection procedures. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -18, the staff finds that the applicant has met the further evaluation criteria, and the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is acceptable for the following reasons:
| |
| * The applicant will perform sufficient inspections for each material
| |
| -environment combination to provide an overall assessment of any aging degradation that may be occurring.
| |
| * The selection of inspections will consider materials, operating environments, industry and plant
| |
| -specific operating experience, engineering evaluations of equipment performance, and susceptibility to aging due to time in service, severity of operating conditions, and lowest design margins.
| |
| * Recurring surveillance and maintenance activities provides the ability to detect aging of the material prior to loss of function.
| |
| * Inspection results will be trended.
| |
| Based on the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.7, item 3 criteria. For those items that apply to LRA Section 3.3.2.2.7.3, the staff determined that the LRA is consistent with the GALL Report, and the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.2.8 Loss of Material Due to General, Pitting, Crevice and Microbiologically
| |
| -Influenced Corrosion
| |
| | |
| Aging Management Review Results 3-417 The staff reviewed LRA Section 3.3.2.2.8 against the criteria in SRP
| |
| -LR Section 3.3.2.2.8. LRA Section 3.3.2.2.8 is associated with LRA Table 3.3.1, item 3.3.1
| |
| -19, and addresses steel piping, piping components and piping elements exposed to soil, which are being managed for loss of material due to general, pitting, crevice, and MIC by the Buried Piping and Tanks Inspection Program. The criteria in SRP
| |
| -LR Section 3.3.2.2.8, state that the loss of material due to general, pitting, crevice, and MIC could occur for steel (with or without coating or wrapping) piping, piping components, and piping elements exposed to soil environment. The SRP
| |
| -LR also states that the Buried Piping and Tanks Inspection Program relies on industry practice, frequency of pipe excavation, and operating experience to manage the effects of loss of material aging effect. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that the Buried Piping and Tanks Inspection Program will use external coatings and wrappings installed to industry standards on buried piping as well as periodic inspections to determine loss of material. The staff noted that the applicant stated, in LRA Section B.2.1
| |
| -22, under the "detection of aging effects" program element that inspections locations would be, in part, based on areas with a history of corrosion problems.
| |
| The staff's evaluation of the applicant's Buried Piping and Tanks Inspection Program is documented in SER Section 3.0.3.3.1. The applicant stated that the Buried Piping and Tanks Inspection Program will manage loss of material due to general, pitting, crevice, and MIC by employing preventive measures such as external coatings and wrappings and performing periodic inspections to detect aging effects. The applicant further stated that, during installation, steel and stainless steel buried piping contained either external coatings or wrappings to mitigate corrosion. The applicant stated that visual inspections will be performed on the protective wraps and coatings to look for evidence of damaged wrapping or coating defects. The applicant stated that if defects are found then the external surface of the pipe will be further inspected for loss of material. The applicant also stated that ultrasonic inspections or other advanced inspection methods may be used to detect loss of material. Additionally, visual inspections will be performed at least once during the 10
| |
| -year period of extended operation or when pipes are excavated for maintenance or other activities. In its review of components associated with item 3.3.1
| |
| -19, the staff finds that the applicant has met the further evaluation criteria, and the applicant's proposal to manage aging using the Buried Piping and Tanks Inspection Program is acceptable for the following reasons:
| |
| * The program includes preventive actions, such as external coatings and wrappings installed to industry standard practices and backfill that will not damage the piping or coatings, and some systems are protected by a cathodic protection system.
| |
| * Periodic visual inspections will be performed starting 10 years prior to the period of extended operation and extend into both 10
| |
| -year periods during the period of exte nded operation to ensure that coatings remain intact or uncoated piping has not degraded.
| |
| * Plant-specific operating experience will be used to inform inspection locations.
| |
| * Alternatives to direct visual inspection, such as pressure tests or ultrasonic inspections, are capable of detecting piping degradation.
| |
| Based on the program identified, the staff concludes that the applicant's program meets SRP
| |
| -LR Section 3.3.2.2.8 criteria. For those items that apply to LRA Section 3.3.2.2.8, the staff determined that the LRA is consistent with the GALL Report, and the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be Aging Management Review Results 3-418 maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.2.9 Loss of Material Due to General, Pitting, Crevice, Microbiologically
| |
| -Influenced Corrosion, and Fouling The staff reviewed LRA Section 3.3.2.2.9 against the following criteria in SRP
| |
| -LR Section 3.3.2.2.9:
| |
| (1) LRA Section 3.3.2.2.9.1, referenced by LRA Table 3.3.1, item 3.3.1
| |
| -20, addresses steel piping, piping components, piping elements, and tanks exposed to fuel oil, which are being managed for loss of material due to general, pitting, crevice, MIC, and fouling by the Fuel Oil Chemistry Program and One
| |
| -Time Inspection Program. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that the One
| |
| -Time Inspection Program will be used to verify the effectiveness of the Fuel Oil Chemistry Program to manage the loss of material through examination of susceptible locations in steel piping, piping components, piping elements, and tanks exposed to fuel oil in the fuel oil system.
| |
| The staff reviewed LRA Section 3.3.2.2.9.1 against the criteria in SRP
| |
| -L R Section 3.3.2.2.9, item 1, which states loss of material due to general, pitting, crevice, MIC, and fouling could occur for steel piping, piping components, piping elements, and tanks exposed to fuel oil. The SRP
| |
| -LR also stated that the existing AMP relies on the Fuel Oil Chemistry Program for monitoring and control of fuel oil contamination to manage loss of material due to corrosion or fouling. Corrosion or fouling may occur at locations where contaminants accumulate. The effectiveness of the fuel oil chemistry control should be confirmed to ensure that corrosion does not occur. The SRP
| |
| -LR also states that the GALL Report recommends further evaluation of programs to manage loss of material due to general, pitting, crevice, MIC, and fouling to verify the effectiveness of the Fuel Oil Chemistry Program. It also states that a one
| |
| -time inspection of selected components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that the component's intended function will be maintained during the period of extended operation.
| |
| The staff's evaluations of the applicant's Fuel Oil Chemistry and One
| |
| -Time Inspection Programs are documented in SER Sections 3.0.3.2.10 and 3.0.3.1.8, respectively. In its review of components associated with item 3.3.1
| |
| -20, the staff finds the applicant' s proposal to manage aging using the One
| |
| -Time Inspection Program to verify the effectiveness of the Fuel Oil Chemistry Program acceptable because the Fuel Oil Chemistry Program was determined to be consistent with the GALL Report.
| |
| Additionally, the applicant stated that the One
| |
| -Time Inspection Program will be used to examine steel piping, piping components, piping elements to verify the effectiveness of the Fuel Oil Chemistry Program. This satisfies the acceptance criteria in SRP
| |
| -LR Section 3.3.2.2.9, item 1; therefore, the applicant's AMR is consistent with GALL Report.
| |
| Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.9, item 1, criteria. For the items that apply to LRA Section 3.3.2.2.9.1, the staff determined that the LRA is consistent with the GALL Report, and the applicant demonstrated that the effects of aging will be adequately Aging Management Review Results 3-419 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).
| |
| (2) LRA Section 3.3.2.2.9.2, referenced by LRA Table 3.3.1, item 3.3.1
| |
| -21, addresses steel heat exchanger components exposed to lubricating oil, which are being managed for loss of material due to general, pitting, crevice, MIC, and fouling by the Lubricating Oil Analysis and One
| |
| -Time Inspection Programs. SRP
| |
| -LR Section 3.3.2.2.9, item 2, states that loss of material due to general, pitting, and crevice corrosion, MIC, and fouling may occur in steel heat exchanger components exposed to lubricating oil. The existing AMP periodically samples and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil control should be confirmed to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage corrosion to verify the effectiveness of lubricating oil programs. A one-time inspection of selected components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component
| |
| -intended functions will be maintained during the period of extended operation.
| |
| The staff's evaluations of the applicant's Lubricating Oil Analysis and One
| |
| -Time Inspection Programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.1.8, respectively. In its review of components associated with item 3.3.1
| |
| -21, the staff finds the applicant's proposal to manage aging using the One
| |
| -Time Inspection Program to verify the effectiveness of the Lubricating Oil Analysis Program acceptable because the Lubricating Oil Analysis Program was determined to be consistent with the GALL Report. Additionally, the applicant stated that the One
| |
| -Time Inspection Program will be used to examine steel heat exchanger components to verify the effectiveness of the Lubricating Oil Analysis Program. This satisfies the acceptance criteria in SRP
| |
| -LR Section 3.3.2.2.9, item 2; therefore, the applicant's AMR is consistent with the GALL Report. Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.9, item 2, criteria. For the items that apply to LRA Section 3.3.2.2.9.2, the staff determined that the LRA is consistent with the GALL Report, and the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.2.10 Loss of Material Due to Pitting and Crevice Corrosion (1) LRA Section 3.3.2.2.10.1, associated with LRA Table 3.3.1, item 3.3.1
| |
| -22, addresses loss of material due to pitting and crevice corrosion in steel piping with elastomer lining or stainless steel cladding exposed to treated water or treated borated water if the cladding or lining is degraded. The applicant stated that this item is not applicable because there are no steel with elastomer lining components exposed to treated borated water in the spent fuel pool cooing system, and GALL Report item VII.A4
| |
| -12 is only applicable to BWR plants.
| |
| The staff reviewed LRA Sections 2.3.3 and 3.3 and the UFSAR and confirmed that no in-scope steel piping with elastomer lining exposed to treated borated water is present in Aging Management Review Results 3-420 the spent fuel pool cooing system. The staff confirmed that GALL Report item VII.A4
| |
| -12, steel with elastomer lining or stainless steel cladding, is only applicable to BWR plants; therefore, it finds the applicant's claim acceptable.
| |
| (2) LRA Section 3.3.2.2.10.2, associated with LRA Table 3.3.1, items 3.3.1
| |
| -23 and 3.3.1
| |
| -24, addresses loss of material due to pitting and crevice corrosion in stainless steel and steel with stainless steel cladding heat exchanger components, and stainless steel and aluminum piping, piping components, and piping elements exposed to treated water.
| |
| The applicant stated that these items are not applicable because they are only applicable to BWRs.
| |
| SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice corrosion may occur in stainless steel and aluminum piping, piping components, piping elements, and for stainless steel and steel with stainless steel cladding heat exchanger components exposed to treated water. The existing AMP monitors and controls reactor water chemistry to manage the aging effects of loss of material from pitting and crevice corrosion. However, high concentrations of impurities in crevices and with stagnant flow conditions may cause pitting or crevice corrosion; therefore, the effectiveness of Water Chemistry Control Programs should be confirmed to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to manage loss of material from pitting and crevice corrosion to verify the effectiveness of Water Chemistry Control Programs. A one
| |
| -time inspection of selected components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that component-intended functions will be maintained during the period of extended operation.
| |
| The staff noted that SRP
| |
| -LR items 3.3.1
| |
| -23 and 3.3.1
| |
| -24 are associated with GALL Report items VII.A4
| |
| -2, VII.A4-5, VII.A4-11, VII.E3
| |
| -7, VII.E3-15, VII.E4
| |
| -4, and VII.E4-14, all of which are associated with BWR spent fuel pool cooling and cleanup, reactor water cleanup, and shutdown cooling systems; therefore, it finds the applicant's claim acceptable. The staff also noted that LRA items with the same component, material, environment, and aging effect combination are managed for aging by items 3.4.1
| |
| -15 and 3.4.1-16 instead of items 3.3.1
| |
| -23 and 3.3.1
| |
| -24, and these alternative items are consistent with the GALL Report's recommended programs.
| |
| (3) LRA Section 3.3.2.2.10.3, is associated with LRA Table 3.3.1, item 3.3.1
| |
| -25, and addresses the copper
| |
| -alloy HVAC piping, piping components, and piping elements in the chlorination, screen wash, service water, and waste processing liquid systems, and copper-alloy heat exchanger components in the containment air handling, containment enclosure air handling, and control building air handling systems exposed to condensation (external), which are being managed for loss of material due to pitting, galvanic or crevice corrosion by the External Surfaces Monitoring, Bolting Integrity Program, or Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Programs.
| |
| The criteria in SRP
| |
| -LR Section 3.3.2.2.10, item 3, states that loss of material due to pitting and crevice corrosion could occur for copper
| |
| -alloy HVAC piping, piping components, and piping elements exposed to condensation (external). The SRP
| |
| -LR also states that the GALL Report recommends further evaluation of a plant
| |
| -specific AMP to ensure that these aging effects are adequately managed in accordance with the Aging Management Review Results 3-421 acceptance criteria described in BTP RLSB
| |
| -1. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that copper
| |
| -alloy piping, copper
| |
| -alloy heat exchanger components, and bolting exposed to condensation (external) will be managed for loss of material due to pitting, galvanic, and crevice corrosion by the External Surfaces Monitoring, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components, and Bolting Integrity Programs.
| |
| The staff's evaluations of the applicant's External Surfaces Monitoring, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components, and Bolting Integrity Programs are documented in SER Sections 3.0.3.2.14, 3.0.3.2.15, and 3.0.3.1.7, respectively. The staff noted that the applicant's External Surfaces Monitoring Program provides for visual inspection of component surfaces for pitting, crevice, and galvanic corrosion at least once per refueling cycle. The staff also noted that the applicant's Bolting Integrity Program provides for visual inspection of bolting for corrosion. In addition, the staff noted that the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program affords opportunistic visual inspections by qualified personnel in accordance with station
| |
| -controlled procedures and processes during the pre
| |
| -planned, periodic system, and component surveillance and maintenance activities. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -25, the staff finds that the applicant met the further evaluation criteria. Additionally, the applicant's proposal to manage aging using the External Surfaces Monitoring, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components, and Bolting Integrity Programs is acceptable because these programs include periodic visual inspections capable of detecting loss of material due to pitting, crevice, or galvanic corrosion.
| |
| Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.10, item 3, criteria. For those items that apply to LRA Section 3.3.2.2.10.3, the staff determined that the LRA is consistent with the GALL Report, and the applicant 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).
| |
| (4) LRA Section 3.3.2.2.10.4, referenced in Table 3.3.1, item 3.3.1
| |
| -26, addresses copper
| |
| -alloy piping, piping components, and piping elements exposed to lubricating oil, which are being managed for loss of material due to pitting and crevice corrosion by the Lubricating Oil Analysis and One
| |
| -Time Inspection Programs. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that the One
| |
| -Time Inspection Program will be used to verify the effectiveness of the Lubricating Oil Analysis Progra m to manage loss of material due to pitting and crevice corrosion through examination of susceptible locations in copper
| |
| -alloy piping, piping components, and copper
| |
| -alloy heat exchanger components exposed to lubricating oil in the chemical and volume control, diesel generator, miscellaneous equipment, instrument air, service water, switchyard systems. The staff reviewed LRA Section 3.3.2.2.10.4 against the criteria in SRP
| |
| -LR Section 3.3.2.2.10, item 4, which states that loss of material due to pitting and crevice corrosion could occur for copper
| |
| -alloy piping, piping components, and piping elements Aging Management Review Results 3-422 exposed to lubricating oil. The SRP
| |
| -LR also states that the existing AMP relies on the periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion. The SRP-LR further states that control of lube oil contaminants may not always have been adequate to preclude corrosion; therefore, the effectiveness of lubricating oil control should be confirmed to ensure that corrosion does not occur. The SRP
| |
| -LR also states that the GALL Report recommends further evaluation of programs to manage corrosion to verify the effectiveness of the Lubricating Oil Analysis Program for which a one-time inspection of selected components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that the component's intended function will be maintained during the period of extended operation.
| |
| The staff's evaluations of the applicant's Lubricating Oil Analysis and One
| |
| -Time Inspection Programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.1.8, respectively. In its review of components associated with item 3.3.1
| |
| -26, the staff finds the applicant's proposal to manage aging using the One
| |
| -Time Inspection Program to verify the effectiveness of the Lubricating Oil Analysis Program acceptable because the Lubricating Oil Analysis Program was determined to be consistent with the GALL Report. Additionally, the applicant stated that the One
| |
| -Time Inspection Program will be used to examine copper
| |
| -alloy piping, piping components, and piping elements to verify the effectiveness of the Lubricating Oil Analysis Program. This satisfies the acceptance criteria in SR P-LR Section 3.3.2.2.10, item 4; therefore, the applicant's AMR is consistent with the GALL Report.
| |
| (5) LRA Section 3.3.2.2.10.5 is associated with LRA Table 3.3.1, item 3.3.1
| |
| -27, and addresses stainless steel and aluminum components in auxiliary systems exposed to condensation (internal) or condensation (external), which are being managed for loss of material due to pitting or crevice corrosion. The criteria in SRP
| |
| -LR Section 3.3.2.2.10, item 5, states that loss of material due to pitting and crevice corrosion could occur for HVAC aluminum piping, piping components, and piping elements and stainless steel ducting and components exposed to condensation. The SRP
| |
| -LR also states that a plant-specific AMP should be evaluated to ensure that these aging effects are adequately managed. The applicant addressed the further evaluation criteria of the SRP-LR by identifying several AMPs to manage the aging effect, as described below.
| |
| The applicant stated the following:
| |
| * The Bolting Integrity Program will be used to manage loss of material due to pitting and crevice corrosion of stainless steel bolting exposed to condensation (external) in the primary component cooling water, screen wash, and service water systems.
| |
| * The Compressed Air Monitoring Program will be used to manage loss of material due to pitting, crevice, and galvanic corrosion for aluminum piping and heat exchanger components (after cooler tubes, filter housing, traps) exposed to condensation (internal) in the diesel generator and instrument air systems. The External Surfaces Monitoring Program will be used to manage loss of material due to pitting and crevice corrosion of aluminum heat exchanger fins exposed to condensation (external) in the control building air handling system. By letter dated October, 2, 2014, the applicant amended the LRA to include managing Aging Management Review Results 3-423 loss of material for stainless steel valve bodies exposed to condensation (external) using the External Surfaces Monitoring Program.
| |
| * The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program will be used to manage pitting, and crevice corrosion of stainless steel HVAC drip pans and piping exposed to condensation (internal) in the containment air handling, containment enclosure air handling, and fuel storage building air handling systems.
| |
| * As amended by letter dated March 5, 2014, the Fire Water System Program will be used to manage loss of material due to pitting and crevice corrosion of aluminum piping components exposed to condensation in the fire protection systems. The applicant also stated that galvanic corrosion and MIC have been added as aging mechanisms.
| |
| The staff's evaluations of the applicant's Bolting Integrity Program, Compressed Air Monitoring Program, Fire Water System Program, External Surfaces Monitoring Program, and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program are documented in SER Sections 3.0.3.1.7, 3.0.3.2.6, 3.0.3.2.8, 3.0.3.2.14, and 3.0.3.2.15, respectively. The staff noted that the Bolting Integrity, Compressed Air Monitoring, Fire Water System, External Surfaces Monitoring, and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Programs all include visual inspection activities that are capable of detecting loss of material due to pitting, crevice, and galvanic corrosion, and MIC in aluminum and stainless steel components. These programs implement corrective action if unacceptable indications of loss of material due to pitting, crevice, galvanic corrosion, or MIC are found. The staff also noted that the Compressed Air Monitoring Program also includes monitoring of air system quality and preventive activities to reduce the potential for presence of moisture and occurrence of corrosion. The staff further noted that components associated with LRA Table 3.3.1, item 3.3.1
| |
| -27, addressed by the Bolting Integrity Program, the Fire Water System Program, the External Surfaces Monitoring Program, and the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program are typically accessible for visual examination during normal operation or routine plant outages. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -27, the staff finds that the applicant has met the further evaluation criteria, and the applicant's proposal to manage aging using the Bolting Integrity Program, Compressed Air Monitoring Program, the Fire Water System Program, External Surfaces Monitoring Program, and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is acceptable for the following reasons:
| |
| * The components associated with LRA Table 3.3.1, item 3.3.1
| |
| -27, are typically accessible for inspection either during normal operation or routine plant outages.
| |
| * Each of the credited programs includes visual inspections that are capable of detecting loss of material due to pitting, crevice, galvanic corrosion, and MIC in aluminum and stainless steel components.
| |
| | |
| Aging Management Review Results 3-424
| |
| * Each credited program includes requirements for implementing corrective actions if unacceptable indications of loss of material due to pitting, crevice, galvanic corrosion, or MIC are found.
| |
| Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.10, item 5, criteria. For those items that apply to LRA Section 3.3.2.2.10.5, the staff determined that the LRA is consistent with the GALL Report, and the applicant 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).
| |
| (6) As amended by letter dated March 5, 2014 (ADAMS Accession No. ML14072A018), LRA Section 3.3.2.2.10.6, is associated with LRA Table 3.3.1, item 3.3.1
| |
| -28, and addresses copper
| |
| -alloy fire protection piping and piping components and tanks in the diesel generator, instrument air, and fire protection systems exposed to condensatio n (internal), which are being managed for loss of material due to pitting, crevice corrosion, and MIC by the Compressed Air Monitoring, the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components, and the Fire Water System Programs.
| |
| The criteria in SRP
| |
| -LR Section 3.3.2.2.10, item 6, states that loss of material due to pitting and crevice corrosion could occur for copper
| |
| -alloy piping, piping components, and piping elements exposed to internal condensation. The SRP
| |
| -LR also states that the GALL Report recommends further evaluation of a plant
| |
| -specific AMP to ensure that these aging effects are adequately managed in accordance with the acceptance criteria described in BTP RLSB
| |
| -1. The applicant addressed the further evaluation criteria of the SRP-LR by stating that copper
| |
| -alloy piping components exposed to condensation will be managed for loss of material due to pitting and crevice corrosion, and MIC by the Compressed Air Monitoring, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components, and Fire Water System Programs.
| |
| The staff's evaluations of the applicant's Compressed Air Monitoring, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components, and Fire Water System Programs are documented in SER Sections 3.0.3.2.6, 3.0.3.2.8, and 3.0.3.2.15, respectively. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -28, the staff finds that the applicant met the further evaluation criteria. Additionally, the staff finds that the applicant's proposal to manage aging using the Compressed Air Monitoring, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components, and Fire Water System Programs is acceptable because these programs conduct internal visual inspections that are capable of detecting loss of material.
| |
| Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.10, item 6, criteria. For those items that apply to LRA Section 3.3.2.2.10.6, the staff determined that the LRA is consistent with the GALL Report, and the applicant 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).
| |
| (7) LRA Section 3.3.2.2.10.7 addresses loss of material due to pitting and crevice corrosion in stainless steel piping, piping components, and piping elements exposed to soil. LRA Section 3.3.2.2.10.7 is associated with LRA Table 3.3.1, item 3.3.1
| |
| -29, and addresses Aging Management Review Results 3-425 stainless steel piping, piping components and piping elements exposed to soil, which are being managed for loss of material due to pitting and crevice corrosion by the Buried Piping and Tanks Inspection Program. The criteria in SRP
| |
| -LR Section 3.3.2.2.10, item 7, states that the loss of material due to pitting, crevice, and MIC could occur for stainless steel piping, piping components, and piping elements exposed to soil. The SRP-LR also states that a plant
| |
| -specific AMP will be used to manage loss of material. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that the Buried Piping and Tanks Inspection Program will use external coatings and wrappings on buried piping as well as periodic inspections to determine loss of material.
| |
| The staff's evaluation of the applicant's Buried Piping and Tanks Inspection Program is documented in SER Section 3.0.3.3.1. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -29, the staff finds that the applicant has met the further evaluation criteria, and the applicant's proposal to manage aging using the Buried Piping and Tanks Inspection Program is acceptable for the following reasons:
| |
| * The program includes preventive actions such as external coatings and wrappings installed to industry standard practices and backfill that will not damage the piping or coatings.
| |
| * Periodic visual inspections will be performed starting 10 years prior to the period of extended operation and extend into both 10
| |
| -year periods during the period of extended operation to ensure that coatings remain intact or uncoated piping has not degraded.
| |
| * Plant-specific operating experience will be used to inform inspection locations.
| |
| * Alternatives to direct visual inspection, such as pressure tests or ultrasonic inspections, are capable of detecting piping degradation.
| |
| Based on the program identified, the staff concludes that the applicant's program meets SRP-LR Section 3.3.2.2.10, item 7, criteria. For those items that apply to LRA Section 3.3.2.2.10.7, the staff determined that the LRA is consistent with the GALL Report, and the applicant 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).
| |
| (8) LRA Section 3.3.2.2.10.8, associated with LRA Table 3.3.1, item 3.3.1
| |
| -30, addresses loss of material due to pitting and crevice corrosion in stainless steel piping, piping components, and piping elements of the BWR standby liquid control system exposed to sodium pentaborate solution. The applicant stated that this item is not applicable because it is only applicable to BWRs. The staff reviewed the SRP
| |
| -LR and LRA Section 3.3 and noted that this item is associated only with BWRs; therefore, it finds the applicant's claim acceptable.
| |
| 3.3.2.2.11 Loss of Material Due to Pitting, Crevice, and Galvanic Corrosion LRA Section 3.3.2.2.11, associated with LRA Table 3.3.1, item 3.3.1
| |
| -31, addresses loss of material due to pitting, crevice, and galvanic corrosion of copper
| |
| -alloy piping, piping components, and piping elements that are exposed to treated water. The applicant stated that Aging Management Review Results 3-426 this item is not applicable because LRA Table 3.3.1, item 3.3.1
| |
| -31, is applicable to BWRs only. The staff reviewed LRA Sections 2.3.4 and 3.4 and found that there are in
| |
| -scope copper
| |
| -alloy instrumentation elements, valve bodies, and heat exchanger components exposed to treated water in the auxiliary steam condensate and feedwater systems. The staff noted that although loss of material due to selective leaching for these components is managed with Selective Leaching of Materials Program, there are no actions identified to manage loss of material due to pitting, crevice, and galvanic corrosion for these components.
| |
| By letter dated January 5, 2011 (ADAMS Accession No. ML103420585), the staff issued RAI 3.3.2.2-1, requesting that the applicant justify why the copper
| |
| -alloy piping, piping components, and piping elements exposed to treated water would not be vulnerable to pitting, crevice, and galvanic corrosion.
| |
| In its response dated February 3, 2011 (ADAMS Accession No. ML110380081), the applicant stated that auxiliary steam condensate, condensate, and feedwater systems were evaluated under Section 3.4 of the LRA, "Aging Management of Steam and Power Conversion Systems," and, therefore, aligned with Section 3.4.2.2.7.1 and item 3.4.1
| |
| -15. The staff noted that components under item LRA Table 3.4.1, item 3.4.1
| |
| -15, are managed for loss of material due to pitting and crevice corrosion in aluminum and copper
| |
| -alloy piping, piping components, and piping elements exposed to treated water by the One
| |
| -Time Inspection and Water Chemistry Programs. The staff's evaluations of the applicant's One
| |
| -Time Inspection and Water Chemistry Programs are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. The staff finds the applicant's response acceptable because adherence to the water chemistry guidelines through the implementation of the Water Chemistry Program minimizes the presence of contaminants that may lead to pitting and crevice corrosion in those components. The One
| |
| -Time Inspection Program provides an inspection opportunity to verify the effectiveness of the Water Chemistry Program. The staff's concern described in RAI 3.3.2.2
| |
| -1 is resolved.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.2.12 Loss of Material Due to Pitting, Crevice, and Microbiologically
| |
| -Influenced Corrosion (1) LRA Section 3.3.2.2.12.1 is associated with LRA Table 3.3.1, item 3.3.1
| |
| -32, and addresses stainless steel, aluminum and copper
| |
| -alloy piping, piping components, and piping elements exposed to fuel oil, which are being managed for loss of material due to pitting, crevice, and MIC by the Fuel Oil Chemistry and One
| |
| -Time Inspection Programs. The staff noted that the LRA states that galvanic corrosion is an additional aging effect that will be managed for the aluminum components in the diesel generator system. The criteria in SRP
| |
| -LR Section 3.3.2.2.12, item 1, state that loss of material due to pitting, crevice, and MIC could occur for stainless steel, aluminum, and copper
| |
| -alloy components exposed to fuel oil. The SRP
| |
| -LR also states that corrosion may occur at locations where contaminants accumulate, and the effectiveness of fuel oil chemistry control should be confirmed to ensure that corrosion does not occur. The SRP
| |
| -LR further states that a one
| |
| -time inspection of selected components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that the Aging Management Review Results 3-427 component's intended function will be maintained during the period of extended operation. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating it will implement the One
| |
| -Time Inspection Program to verify the effectiveness of the Fuel Oil Chemistry Program to ensure that these aging effects are adequately managed. The staff's evaluations of the applicant's Fuel Oil Chemistry and One
| |
| -Time Inspection Programs are documented in SER Sections 3.0.3.2.10 and 3.0.3.1.8, respectively. The staff noted that the Fuel Oil Chemistry Program includes activities to monitor fuel o il chemistry quality, remove water, and clean and inspect the tanks. The staff also noted that the One
| |
| -Time Inspection Program will inspect a sample of components in systems that contain fuel oil for evidence of effective management of loss of material. In its review of components associated with LRA Table 3.3.1, item 3.3.1
| |
| -32, the staff finds the applicant's proposal to manage aging using the Fuel Oil Chemistry and One
| |
| -Time Inspection Programs acceptable because the Fuel Oil Chemistry Program includes activities to ensure contaminants that could cause corrosion do not accumulate. Additionally, the One
| |
| -Time Inspection Program provides for visual inspections to confirm the effectiveness of the Fuel Oil Chemistry Program, which is consistent with the guidance in the SRP
| |
| -LR. Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.12, item 1, criteria. For those items that apply to LRA Section 3.3.2.2.12.1, the staff determined that the LRA is consistent with the GALL Report, and the applicant 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).
| |
| (2) LRA Section 3.3.2.2.12.2, referenced in Table 3.3.1, item 3.3.1
| |
| -33, addresses stainless steel piping, piping components, and piping elements exposed to lubricating oil, which are being manage for loss of material due to pitting, crevice, and MIC by the Lubricating Oil Analysis and One
| |
| -Time Inspection Programs. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that the One
| |
| -Time Inspection Program wil l be used to verify the effectiveness of the Lubricating Oil Analysis Program to manage loss of material due to pitting, crevice, and MIC through examination of susceptible locations in stainless steel piping, stainless steel drip pan components, stainless steel flame arrestor, stainless steel tank, and stainless steel heat exchanger components exposed to lubricating oil in the chemical and volume control, diesel generator, fire protection, instrument air, miscellaneous equipment, oil collection for reactor coolant pumps, and switchyard systems.
| |
| The staff reviewed LRA Section 3.3.2.2.12.2 against the criteria in SRP
| |
| -LR Section 3.3.2.2.12, item 2, which states that loss of material due to pitting, crevice, and MIC could occur in stainless steel piping, piping components, and piping elements exposed to lubricating oil. The SRP
| |
| -LR also states that the existing AMP relies on the periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby an environment that is not conducive to corrosion. The SRP
| |
| -LR further states that control of lube oil contaminants may not always have been adequate to preclude corrosion; therefore, the effectiveness of lubricating oil control should be confirmed to ensure that corrosion does not occur. The SRP
| |
| -LR also states that the GALL Report recommends further evaluation of programs to manage corrosion Aging Management Review Results 3-428 to verify the effectiveness of the Lubricating Oil Analysis Program for which a one
| |
| -time inspection of selected components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that the component's intended function will be maintained during the period of extended operation.
| |
| The staff's evaluations of the applicant's Lubricating Oil Analysis and One
| |
| -Tim e Inspection Programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.1.8, respectively. In its review of components associated with item 3.3.1
| |
| -33, the staff finds the applicant's proposal to manage aging using the One
| |
| -Time Inspection Program to verify the effectiveness of the Lubricating Oil Analysis Program acceptable because the Lubricating Oil Analysis Program was determined to be consistent with the GALL Report. Additionally, the applicant stated that the One
| |
| -Time Inspection Program will be used to examine stainless steel piping, piping components, piping elements, and heat exchanger components to verify the effectiveness of the Lubricating Oil Analysis Program. This satisfies the acceptance criteria in SRP
| |
| -LR Section 3.3.2.2.12, item 2; therefore, the applicant's AMR is consistent with the GALL Report.
| |
| Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.12, item 2, criteria. For the items that apply to LRA Section 3.3.2.2.12.2, the staff determined that the LRA is consistent with the GALL Report, and the applicant demonstrated that the effect of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.2.13 Loss of Material Due to Wear LRA Section 3.3.2.2.13 is associated with LRA Table 3.3.1, item 3.3.1
| |
| -34, and addresses elastomer seals and components exposed to air
| |
| -indoor uncontrolled (internal or external) which are being managed for loss of material due to wear by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program for internal surfaces and the External Surfaces Monitoring Program for external surfaces. The criteria in SRP
| |
| -LR Section 3.3.2.2.13 state that loss of material due to wear could occur in the elastomer seals and components exposed to air
| |
| -indoor uncontrolled (internal or external). The SRP
| |
| -LR also states that the GALL Report recommends further evaluation of a program to ensure that the aging effects are adequately managed. The applicant addressed the further evaluation criteria of the SRP
| |
| -LR by stating that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is adequate to manage the aging effects on the internal surfaces of these components, and the External Surfaces Monitoring Program is adequate to manage the aging effects on the external surfaces of these components.
| |
| The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff noted that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program provides for inspections of opportunity, performed during pre
| |
| -planned, periodic system and component surveillances or during maintenance activities when the systems are opened and the surfaces are made accessible for visual inspection. The staff also noted that for elastomeric materials, the program uses tactile techniques, which include scratching, bending, folding, stretching, and pressing in conjunction with the visual examinations.
| |
| | |
| Aging Management Review Results 3-429 The staff's evaluation of the applicant's Inspection of External Surfaces Monitoring Program is documented in SER Section 3.0.3.2.14. The staff noted that the External Surfaces Monitoring Program uses periodic system inspections and walkdowns to monitor for materials degradation and leakage. The staff also noted that for elastomeric materials, the program uses tactile techniques, which include scratching, bending, folding, stretching, and pressing in conjunction with the visual examinations.
| |
| The staff finds that the applicant met the further evaluation criteria and the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program and the External Surfaces Monitoring Program is acceptable because the program uses visual inspections and tactile techniques that are capable of detecting loss of material due to wear before loss of intended function.
| |
| Based on the programs identified, the staff concludes that the applicant's programs meet SRP
| |
| -LR Section 3.3.2.2.13 criteria. For those items that apply to LRA Section 3.3.2.2.13, the staff determined that the LRA is consistent with the GALL Report, and the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.2.14 Loss of Material Due to Cladding Breach The staff reviewed LRA Section 3.3.2.2.14 against the criteria in SRP
| |
| -LR Section 3.3.2.2.14. LRA Section 3.3.2.2.14, associated with LRA Table 3.3.1, item 3.3.1
| |
| -35, addresses loss of material due to cladding breach in pump casings of steel with stainless steel cladding exposed to treated borated water. The applicant stated that this item is not applicable because the plant's CVCS does not contain pump casings comprised of steel with stainless steel cladding. The staff reviewed LRA Sections 2.3.3 and 3.3 and the UFSAR and confirmed that no in
| |
| -scope pump casings of steel with stainless steel cladding exposed to treated borated water are present in the auxiliary systems; therefore, it finds the applicant's claim acceptable.
| |
| 3.3.2.2.15 Quality Assurance for Aging Management of Nonsafety
| |
| -Related Components SER Section 3.0.4 documents the staff's evaluation of the applicant's QA Program.
| |
| 3.3.2.3 Aging Management Review Results Not Consistent with or Not Addressed in the GALL Report In LRA Tables 3.3.2
| |
| -1 through 3.3.2-45, the staff reviewed additional details of the AMR results for material, environment, AERM, and AMP combinations not consistent with or not addressed in the GALL Report.
| |
| In LRA Tables 3.3.2
| |
| -1 through 3.3.2
| |
| -45, via Notes F
| |
| -J, the applicant indicated which combinations of component type, material, environment, and AERM do not correspond to an item in the GALL Report. The applicant provided further information about how it will manage the aging effects. Specifically, Note F indicates that the material for the AMR item component is not evaluated in the GALL Report. Note G indicates that the environment for the AMR item component and material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR item component, material, and environment combination is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the Aging Management Review Results 3-430 item component, material, and environment combination is not applicable. Note J indicates that neither the component nor the material and environment combination for the item is evaluated in the GALL Report.
| |
| For component type, material, and environment combinations not evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine if the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. The staff's evaluation is documented in the following sections. 3.3.2.3.1 Auxiliary Boiler
| |
| -Aging Management Evaluation
| |
| -LRA Table 3.3.2
| |
| -1 The staff reviewed LRA Table 3.3.2
| |
| -1, which summarizes the results of AMR evaluations for the auxiliary boiler system component groups.
| |
| In LRA Tables 3.3.2
| |
| -1, 3.3.2-17, and 3.3.2-40, the applicant stated that the steel bolting exposed to air
| |
| -outdoor is being managed for loss of preload by the Bolting Integrity Program. The AMR item cites generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination because even though steel bolting exposed to air
| |
| -outdoor is not specifically addressed in the GALL Report, Table IX.E of the GALL Report states that loss of preload can occur independent of environmental conditions because it can be caused by thermal or mechanical effects. Additionally, Table IX.C of the GALL Report states that steel material is susceptible to a variety of aging effects and mechanisms, including loss of material due to general, pitting, and crevice corrosion. The staff noted that the applicant addressed loss of material in additional items for each of these components; therefore, the aging effect of concern is loss of preload, which is addressed in the AMR.
| |
| The staff's evaluation of the applicant's Bolting Integrity Program is documented in SER Section 3.0.3.1.7. While there is no AMR for loss of preload of steel bolting exposed to air
| |
| -outdoor in the auxiliary system, the GALL Report has items for other material bolting exposed to air
| |
| -outdoor managed by the Bolting Integrity Program. The staff finds the applicant's proposal to manage aging using the Bolting Integrity Program acceptable because the Bolting Integrity Program conducts bolting assembly and maintenance control such as application of appropriate gasket alignment, torque, lubricants, and preload. Additionally, the program inspects for leakage and loose or missing nuts, which verify that the aging effect, loss of preload, will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation.
| |
| In LRA Tables 3.3.2
| |
| -1, 3.3.2-12, and 3.3.2
| |
| -40, the applicant stated that aluminum valve body, flame arrestor, and piping and fittings exposed to air
| |
| -outdoor (external) are being managed for loss of material by the External Surfaces Monitoring Program. The AMR item cites generic Note G. The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination because, even though the GALL Report does not have an aging effect or AMP for aluminum exposed to air-outdoor (external), the GALL Report does state that aluminum materials exposed to Aging Management Review Results 3-431 condensation are subject to loss of material due to pitting and crevice corrosion. The GALL Report also states that exposure to outdoor weather conditions can be considered a condensation environment.
| |
| The staff's evaluation of the applicant's External Surfaces Monitoring Program is documented in SER Section 3.0.3.2.14. The staff finds that the applicant's proposal to manage aging using the External Surfaces Monitoring Program acceptable because the program uses periodic visual inspections that would detect loss of material in aluminum components.
| |
| In LRA Tables 3.3.2
| |
| -1 and 3.3.2
| |
| -9, the applicant stated that aluminum valves and galvanized steel damper housings exposed to air
| |
| -outdoor (internal) are being managed for loss of materia l due to general, pitting, and crevice corrosion with the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The AMR items cite generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination. Table IX.D of the GALL Report states that the outdoor air environment includes moist, possibly salt laden, air where the component is exposed to local weather conditions, including precipitation and wind. Section VII of the GALL Report states that aluminum and steel components exposed to condensation or raw water are susceptible to loss of material due to general, pitting, and crevice corrosion.
| |
| The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff finds the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program acceptable because the program includes periodic visual inspections performed during maintenance and surveillance activities, which can identify localized discoloration and surface irregularities such as rust, scale, deposits, and surface pitting that could result in a loss of the component
| |
| -intended function.
| |
| Subsequent to the issuance of the SER with Open Items, by letter of March 5, 2014, the applicant amended the LRA to include metallic components with internal coatings exposed to fuel oil and raw water. The staff's evaluation of the AMR for these components is discussed below. Metallic Components with Internal Coatings Exposed to Fuel Oil and Raw Water. As amended by letter dated March 5, 2014, LRA Tables 3.3.2
| |
| -1, 3.3.2-4, 3.3.2-12, 3.3.2-15, 3.3.2-26, 3.3.2-36, 3.3.2-37, 3.3.2-44 (the staff noted that there is an editorial error in the applicant's letter in that LRA Table 3.3.2
| |
| -44 is cited as LRA Table 3.4.2
| |
| -44), and 3.4.2
| |
| -4 state that internally coated metallic piping, fittings, and tanks exposed to fuel oil and raw water will be managed for loss of coating integrity by the Open
| |
| -Cycle Cooling Water System, Fire Water System, Fuel Oil Chemistry, and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Programs. The AMR items cite generic Note G.
| |
| The staff's evaluation of the applicant's Open
| |
| -Cycle Cooling Water System, Fire Water System, Fuel Oil Chemistry, and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Programs is documented in SER Sections 3.0.3.2.3, 3.0.3.2.8, 3.0.3.2.10, and 3.0.3.2.15, respectively. In addition, the staff's evaluation of how the applicant is going to manage loss of coating integrity for coatings that have been installed on the internal surfaces of Aging Management Review Results 3-432 in-scope components (i.e., piping, fittings, and tanks) is documented in SER Section 3.0.3.4.1. The staff finds the applicant's proposal to manage loss of coating integrity using the Open
| |
| -Cycle Cooling Water System, Fire Water System, Fuel Oil Chemistry, and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Programs acceptable because the programs include periodic inspections of internal coatings by qualified individuals, capable of detecting loss of coating integrity.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.3.2 Boron Recovery System
| |
| -Aging Management Evaluation
| |
| -LRA Table 3.3.2
| |
| -2 The staff reviewed LRA Table 3.3.2
| |
| -2, which summarizes the results of AMR evaluations for the boron recovery system component groups.
| |
| In LRA Tables 3.3.2
| |
| -2, 3.3.2-3, 3.3.2-4, 3.3.2-9, 3.3.2-10, 3.3.2-11, 3.3.2-12, 3.3.2-16, 3.3.2-19, 3.3.2-20, 3.3.2-21, 3.3.2-22, 3.3.2-24, 3.3.2-25, 3.3.2-29, 3.3.2-30, 3.3.2-31, 3.3.2-32, 3.3.2-33, 3.3.2-35, 3.3.2-37, 3.3.2-39, 3.3.2-42, 3.3.2-44, and 3.3.2
| |
| -45, the applicant stated that the stainless steel bolting exposed to air
| |
| -indoor is being managed for loss of preload by the Bolting Integrity Program. The AMR item cites generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination. Even though stainless steel bolting exposed to air
| |
| -indoor is not specifically addressed in the GALL Report, Table IX.E of the GALL Report states that loss of preload can occur independent of environmental conditions because it can be caused by thermal or mechanical effects. Additionally, Table IX.C of the GALL Report states that stainless steel material is susceptible to a variety of aging effects and mechanisms, including loss of material due to pitting and crevice corrosion and cracking due to SCC. The staff noted that the environment of interest, air
| |
| -indoor, would not induce SCC or loss of material in stainless steel material because stainless steel is inherently resistant to corrosion in the air
| |
| -indoor environment. Therefore, the aging effect of concern is loss of preload, which is addressed in the AMR.
| |
| The staff's evaluation of the applicant's Bolting Integrity Program is documented in SER Section 3.0.3.1.7. While there is no AMR for loss of preload of stainless steel bolting exposed to air-indoor in the auxiliary system, the GALL Report has items for other material bolting exposed to air-indoor managed by the Bolting Integrity Program. The staff finds the applicant's proposal to manage aging using the Bolting Integrity Program acceptable because the Bolting Integrity Program conducts bolting assembly and maintenance control such as application of appropriate gasket alignment, torque, lubricants, and preload. Additionally, the program inspects for leakage and loose or missing nuts, which verify that the aging effect, loss of preload, will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging for these Aging Management Review Results 3-433 components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.3.3 Chemical and Volume Control System
| |
| -Aging Management Evaluation
| |
| -LRA Table 3.3.2
| |
| -3 The staff reviewed LRA Table 3.3.2
| |
| -3, which summarizes the results of AMR evaluations for the CVCS component groups.
| |
| The staff's evaluation for stainless steel bolting, exposed to air
| |
| -indoor, and managed for loss of preload by the Bolting Integrity Program citing generic Note G, is documented in SER Section 3.3.2.3.2.
| |
| In LRA Table 3.3.2
| |
| -3, the applicant stated that the nickel
| |
| -alloy flexible hoses exposed to treated borated water are being managed for loss of material by the Water Chemistry Program. The AMR item cites generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination because even though nickel alloys exposed to treated borated water are not specifically addressed in the GALL Report, Chapter VII of the GALL Report indicates that nickel alloys exposed to aqueous environments are susceptible to loss of material.
| |
| The staff's evaluation of the applicant's Water Chemistry Program is documented in SER Section 3.0.3.1.2. The staff noted that the Water Chemistry Program relies upon periodic monitoring and control of detrimental contaminants in the water to manage loss of material. The staff also notes that the GALL Report's guidance for loss of material of stainless steel in treated borated water is part of the Water Chemistry Program, and this aging effect would be very similar to that of nickel alloys in treated borated water. The staff finds the applicant's proposal to manage aging using the Water Chemistry Program acceptable because it employs the use of chemistry sampling to ensure that chemical impurities are minimized to reduce aging due to loss of material, which is similar to guidance observed in the GALL Report.
| |
| In LRA Tables 3.3.2-3, 3.3.2-12, 3.3.2-15, and 3.3.2
| |
| -23, the applicant stated that elastomer flexible hose exposed to fuel oil or lubricating oil (internal) are being managed for hardening and loss of strength with the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The AMR items cite generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination because the GALL Report, in Table IX.C, states that elastomers are susceptible to hardening and loss of strength at temperatures over about 95 °F (35 °C) or when exposed to additional aging factors such as ozone, oxidation, and radiation. The staff noted that the environment of interest, lubricating oil (internal), has the potential for being in the temperature range for elastomer susceptibility to aging; therefore, the aging effect of concern is hardening and loss of strength, which is addressed in the AMR. The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff finds Aging Management Review Results 3-434 the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program acceptable for the following reasons:
| |
| * The program includes periodic visual inspections performed during maintenance a nd surveillance activities, which can identify localized discoloration and surface irregularities.
| |
| * The program includes non
| |
| -visual examinations, such as scratching, which will screen for residues and breakdown of the material, and stretching and pressing, which will evaluate the material resiliency to determine if hardening and loss of strength are occurring that could result in a loss of the component
| |
| -intended function.
| |
| In LRA Tables 3.3.2
| |
| -3, 3.3.2-5, 3.3.2-6, 3.3.2-7, 3.3.2-8, 3.3.2-11, 3.3.2-16, 3.3.2-18, 3.3.2-20, 3.3.2-23, 3.3.2-28, and 3.3.2
| |
| -39, the applicant stated that the elastomer flexible hoses and flexible connectors exposed to air with borated water leakage (external) are being managed for hardening and loss of strength by the External Surfaces Monitoring Program. The AMR items cite generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination because the GALL Report, item VII.A3
| |
| -1, states that elastomers are susceptible to hardening and loss of strength, due to elastomer degradation when exposed to treated borated water. The environment of interest, air with borated water leakage, contains borated water that would make the material susceptible to hardening and loss of strength, which is addressed in the AMR.
| |
| The staff's evaluation of the applicant's External Surfaces Monitoring Program is documented in SER Section 3.0.3.2.14. The staff noted that the applicant's program includes non
| |
| -visual examinations such as scratching to determine if scale or residues are present or determine if there is a breakdown of material, bending, or folding of the elastomer to detect cracking that initiates at the surface, stretching, and pressing to determine the resistance of the material to hardening effects, and pressing to gauge the materials resiliency. The staff finds that the applicant's proposal to manage aging using the External Surfaces Monitoring Program acceptable because the program includes periodic visual inspections as well as non
| |
| -visual tactile examinations to detect hardening and loss of strength of the component.
| |
| In LRA Tables 3.3.2
| |
| -3, 3.3.2-29, 3.3.2-37, and 3.3.2
| |
| -40, the applicant stated that for nickel
| |
| -alloy components exposed to air with borated water leakage there is no aging effect and no AMP is proposed. The AMR items cite generic Note G and plant
| |
| -specific Note 1. Plant
| |
| -specific Note 1 states the following:
| |
| NUREG-1801 does not include air with borated water leakage for nickel
| |
| -alloy components. Similar to V.F
| |
| -13 for stainless steel, there are no aging effects for nickel alloy in air with borated water leakage. Additionally, the American Welding Society (AWS) "Welding Handbook" (Seventh Edition, Volume 4, 1982, Library of Congress) identifies that nickel chromium alloy materials that are alloyed with iron, molybdenum, tungsten, cobalt or copper in various combinations have improved corrosion resistance.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant's use of generic Note G for these items is appropriate in that the GALL Report, Revision 1, does not Aging Management Review Results 3-435 include entries for nickel alloys exposed to air with borated water leakage. The staff notes that the GALL Report, Revision 2, dated December 31, 2010, does include entries for nickel alloys exposed to air with borated water leakage. These entries indicate that no AERM is present for this material environment combination. The staff also notes these items in Revision 2 of the GALL Report are based in part on EPRI Report 1000975, "Boric Acid Corrosion Guidebook, Revision 1." This report contains data (p. 4
| |
| -43) showing that "[t]here was no measurable corrosion of stainless steel piping surfaces or Inconel weld metal joining the stainless steel and carbon steel piping sections." The staff, therefore, concurs with the applicant's assessment that aging management is not necessary for nickel
| |
| -alloy components exposed to air with borated water leakage.
| |
| In LRA Tables 3.3.2
| |
| -3, 3.3.2-4, 3.3.2-5, 3.3.2-11, 3.3.2-16, 3.3.2-19, 3.3.2-29, 3.3.2-30, 3.3.2-31, 3.3.2-35, 3.3.2-37, and 3.3.2
| |
| -39, the applicant stated that, for glass piping elements exposed to air
| |
| -with borated water leakage (external), there is no aging effect and no AMP is proposed. The AMR items cite generic Note G. The staff reviewed the associated items in the LRA and confirmed that no aging effect is applicable for this component, material, and environment combination because the GALL Report, item V.F
| |
| -9, states that, for an environment of treated borated water there is no AERM and no recommended AMP. Additionally, the air with borated water leakage environment is no more severe than the treated borated water environment.
| |
| The staff's evaluation of stainless steel heat exchanger components exposed to treated borated water that are being managed for reduction of heat transfer due to fouling by the Water Chemistry Program and the One
| |
| -Time Inspection Program, citing generic Note H, is documented in SER Section 3.2.2.2.4, item 2. By letter dated May 29, 2012 (ADAMS Accession No. ML12144A441), the staff issued RAI 3.2.1.48
| |
| -1, requesting that the applicant describe how the effectiveness of the Water Chemistry Program to manage reduction of heat transfer will be verified for stainless steel components exposed to treated borated water with greater than 5 ppb oxygen. This issue was identified as Open Item OI 3.2.2.1
| |
| -1. In its response dated June 19, 2012 (ADAMS Accession No. ML12178A405), the applicant revised the LRA to add the One
| |
| -Time Inspection Program to verify the effectiveness of the Water Chemistry Program to manage reduction of heat transfer for stainless steel heat exchanger tubes exposed to treated borated water. The staff finds the applicant's response acceptable because the effectiveness of the Water Chemistry Program will be verified by the applicant to ensure that potential fouling does not lead to loss of intended function during the period of extended operation. In addition, the staff evaluated the applicant's Water Chemistry and One-Time Inspection Programs, documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. The staff finds the applicant's proposal to manage aging using the Water Chemistry and One
| |
| -Time Inspection Programs acceptable, because the Water Chemistry Program establishes the plant water chemistry control parameters and their limits to mitigate aging and identifies the actions required if the parameters exceed the limits, and the One
| |
| -Time Inspection Program prescribes appropriate visual or other inspection techniques capable of detecting fouling prior to loss of intended function, consistent with the revised GALL Report guidance in LR
| |
| -ISG-2011-01. Based on its review, 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). The staff's concern regarding Aging Management Review Results 3-436 reduction of heat transfer of heat exchanger tubes in auxiliary systems and described in RAI 3.2.1.48-1 is resolved.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.3.4 Chlorination System
| |
| -Aging Management Evaluation
| |
| -LRA Table 3.3.2
| |
| -4 The staff reviewed LRA Table 3.3.2
| |
| -4, which summarizes the results of AMR evaluations for the chlorination system component groups.
| |
| The staff's evaluation for stainless steel bolting, exposed to air
| |
| -indoor and being managed for loss of preload by the Bolting Integrity Program citing generic Note G, is documented in SER Section 3.3.2.3.2.
| |
| In LRA Table 3.3.2
| |
| -4, the applicant stated that the stainless steel bolting exposed to condensation is being managed for loss of material by the Bolting Integrity Program. The AMR item cites generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination. Even though stainless steel bolting exposed to condensation is not specifically addressed in the GALL Report, Table IX.C of the GALL Report states that stainless steel material is susceptible to a variety of aging effects and mechanisms, including loss of material due to pitting and crevice corrosion and cracking due to SCC. The staff noted that the environment of interest, condensation, would not induce SCC in stainless steel material because stainless steel is inherently resistant to SCC in the condensation environment and becomes susceptible to SCC only at temperatures above 140 °F (60 °C); therefore, the aging effect of concern is loss of material, which is addressed in the AMR.
| |
| The staff's evaluation of the applicant's Bolting Integrity Program is documented in SER Section 3.0.3.1.7. While there is no AMR for loss of material of stainless steel bolting exposed to condensation in the auxiliary system, the GALL Report has items for loss of material of other material bolting managed by the Bolting Integrity Program. The staff finds the applicant's proposal to manage aging using the Bolting Integrity Program acceptable because the Bolting Integrity Program inspects the bolting through periodic visual inspections to verify that the aging effect, loss of material, will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation.
| |
| In LRA Tables 3.3.2
| |
| -4, 3.3.2-9, 3.3.2-11, 3.3.2-20, 3.3.2-26, and 3.3.2
| |
| -35, the applicant stated that for polymer [polyvinyl chloride (PVC), polyvinylidene fluoride (PVDF), polypropylene, fluoropolymer, polycarbonate, plastic and polyolefin] piping, piping components, and piping elements, flexible hose, tanks, and instrument elements exposed to air
| |
| -indoor uncontrolled (internal or external) and air
| |
| -indoor controlled external environments, there is no aging effect, and no AMP is proposed. The AMR items cite generic Note F. These items also cite plant
| |
| -specific Notes 1 or 2. Plant
| |
| -specific Note 2 states the following:
| |
| | |
| Aging Management Review Results 3-437 Unlike metals, polymers do not display corrosion rates. Rather than depending on an oxide layer for protection, they depend on chemical resistance to the environment to which they are exposed. The plastic is either completely resistant to the environment or it deteriorates. Therefore, acceptability for the use of polymers within a given environment is a design driven criterion. Once the appropriate material is chosen, the system will have no aging effects. This is consistent with plant operating experience.
| |
| The staff noted that, as identified in Engineering Materials Handbook
| |
| -Engineering Plastics , ASM International, Copyright 1988, rigid polymers are unaffected by water, concentrated alkalis, non-oxidizing acids, oils, ozone, sunlight, or humidity changes. The staff also noted that, unlike metals, thermoplastics do not display corrosion rates, and rather than depend on an oxide layer for protection, they depend on chemical resistance to the environments to which they are exposed and the use of thermoplastics in power plant environments is a design
| |
| -driven criterion. The staff further noted that thermoplastic materials are impervious and, once selected for the environment, will not have any significant age
| |
| -related degradation. The staff reviewed the associated items in the LRA and confirmed that no aging effect is applicable for this component, material, and environment combination because there is no indication in the industry that polymers or thermoplastics exposed to an internal or external indoor air environment have any aging effects requiring management. Additionally, the generally low operating temperatures and historically good chemical resistance data for polymer components, combined with a lack of historically negative operating experience, indicate that polymers are not likely to experience any degradation from the non
| |
| -aggressive indoor air.
| |
| In LRA Tables 3.3.2-4, 3.3.2-15, and 3.3.2
| |
| -36, the applicant stated that, for fiberglass piping and fittings and filter housings exposed to condensation (external) or raw water (internal), there is no aging effect, and no AMP is proposed. The AMR items cite generic Note F and plant
| |
| -specific Notes 1, 5, or 6, which state that "[f]iberglass components in Condensation environment (external) or Raw Water environment (internal) are not exposed to high levels of ultraviolet radiation, high temperatures, or ozone, and therefore have no aging effects that require aging management. This is consistent with plant operating experience." The staff reviewed the associated items in the LRA and found that fiberglass piping exposed to condensation (external) or raw water (internal) is not specifically addressed in the GALL Report; however, the staff noted that the environments of interest could cause water infiltration into the fiberglass, which could induce blistering and spalling or cracking. By letter dated January 5, 2011, the staff issued RAI 3.3.2.3.4
| |
| -1, requesting that the applicant state why the specific specification and grade of fiberglass material used in these components is not susceptible to blistering and spalling or cracking when exposed to condensation environment (external) or raw water environment (internal) or propose how the aging effects will be managed.
| |
| In its response dated February 3, 2011, the applicant stated that portions of the chlorination system, and all of the fire protection system's fiberglass piping, is constructed of an epoxy resin type of material. Based on technical input from the manufacturer, there is no industry experience of blistering, spalling, or cracking due to water absorption in fiberglass piping constructed with the epoxy resin. The applicant also stated that fiberglass reinforced vinyl ester pipe is used in the chlorination system in the service water pumphouse and the intake and discharge structures to supply chlorinated raw water to the pump forebay and to the seawater inlet. The maximum design temperature for this piping of 100 °F and the maximum seawater inlet temperature is 65 °F at Seabrook. The applicant further stated that only hot water in the Aging Management Review Results 3-438 range of 170
| |
| -180 °F or above can cause blistering, spalling, or cracking in vinyl ester resin based fiberglass pipe. The applicant stated that the travelling screen system uses fiberglass traveling screen enclosures, which are only exposed to condensation or raw water in the spray form. The staff reviewed The Corrosion Resistant Materials Handbook, by D.J. De Renzo and Ibert Mellan, and found that both fiberglass reinforced epoxy pipe and reinforced vinyl ester resin pipe are acceptable for use up to 200 °F in brine and 10 percent salt water and chlorinated water up 200 ppm chlorine. The staff also noted that reinforced vinyl ester resin pipe is acceptable for use in chlorine saturated brine up 150 °F and saturated chlorinated water up to 200 °F; however, fiberglass reinforced epoxy pipe is not recommended under these conditions.
| |
| The staff reviewed the fiberglass items in the LRA associated with the fire protection and screen wash system and confirmed that no aging effect is applicable for this component, material, and environment combination for the following reasons:
| |
| * For the fire protection system, LRA Table 3.3.2
| |
| -15, the components are constructed of an epoxy resin type of material, which does not have aging effects until exposed to temperatures above 170 °F, which is above the fire protection systems design temperature.
| |
| * For the screen wash system, LRA Table 3.3.2
| |
| -36, the components are only exposed to raw water as a spray or condensation. Neither of these environments have a driving force for water penetration and blistering.
| |
| Based on a review of the UFSAR, the staff could not determine the chlorine level of the water in the chlorination system such that a determination of no aging effects could be warranted. By letter dated March 30, 2011, the staff issued a followup to RAI 3.3.2.3.4
| |
| -1, requesting that the applicant state the chlorine concentration for in
| |
| -scope fiberglass pipe in the chlorination system. If it exceeds 200 ppm, the staff asked that the applicant state why there is no aging effect or propose an AMP.
| |
| In its response dated April 22, 2011, the applicant stated that the components exposed to chlorine are constructed of fiberglass reinforced vinyl ester or bisphenol
| |
| -A polyester. The applicant also stated that, based on input from the vendor of the components, given the operating parameters of the system
| |
| -less than 65 °F, pH greater than 10, and no direct UV exposure-and plant-specific operating experience to date, there is no potential aging effect.
| |
| The staff did not find the applicant's response acceptable because, based on independent research, the staff does not agree with the applicant's assessment that there is no potential aging effect for these components. While the applicant's response to the RAI, and the staff's independent research, established that the materials are suitable for the design parameters of the system, proper design does not establish the basis for a 60
| |
| -year life with no aging effects when the environment is an oxidizer and the material is an organic polymer. Therefore, by letter dated May 23, 2011, the staff issued a followup to RAI 3.3.2.3.4
| |
| -1, requesting that the applicant state what inspections have been performed to establish a baseline of operating experience and what inspections will be conducted to manage aging of the fiberglass piping and fittings in the chlorination system exposed to raw water, including sodium hypochlorite.
| |
| | |
| Aging Management Review Results 3-439 In its response dated June 2, 2011, the applicant stated that, during the April 2011 RFO, the chlorination system piping was disassembled, and the piping was found to be in excellent condition with no signs of age
| |
| -related degradation. The applicant revised the LRA to include a one-time inspection of the chlorination system fiberglass piping to validate that no aging effect is occurring. The applicant also revised its UFSAR supplement, LRA Section A.2.1.20, to reflect that the One
| |
| -Time Inspection Program will be used to manage the aging effects of cracking, blistering, and change in color (i.e., material properties) for fiberglass piping in the chlorination system. The staff finds the applicant's response acceptable for the following reasons:
| |
| * The applicant identified the correct potential aging effects for this material and environment combination.
| |
| * The applicant revised the LRA to include a one
| |
| -time inspection of fiberglass piping in the chlorination system to verify that aging does not occur.
| |
| * The One-Time Inspection Program includes determination of an appropriate sample size, identification of inspection locations, and visual inspections that can detect the potential aging effects.
| |
| The staff's concern described in RAI 3.3.2.3.4
| |
| -1 is resolved.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant 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).
| |
| In LRA Tables 3.3.2
| |
| -4, 3.3.2-9, and 3.3.2
| |
| -37, the applicant stated that for polymer (PVC) piping and fittings, and filter housing exposed to condensation (internal or external) environment, there is no aging effect, and no AMP is proposed. The AMR items cite generic Note F. These items also cite plant
| |
| -specific Notes 1 or 2. Plant
| |
| -specific Note 2 states the following:
| |
| Unlike metals, polymers do not display corrosion rates. Rather than depending on an oxide layer for protection, they depend on chemical resistance to the environment to which they are exposed. The plastic is either completely resistant to the environment or it deteriorates. Therefore, acceptability for the use of polymers within a given environment is a design driven criterion. Once the appropriate material is chosen, the system will have no aging effects. This is consistent with plant operating experience.
| |
| The staff noted that, as identified in Engineering Materials Handbook
| |
| -Engineering Plastics , American Society for Metals International, Copyright 1988, rigid polymers are unaffected by water, concentrated alkalis, non
| |
| -oxidizing acids, oils, ozone, sunlight, or humidity changes. The staff also noted that, unlike metals, thermoplastics do not display corrosion rates, and rather than depend on an oxide layer for protection, they depend on chemical resistance to the environments to which they are exposed and the use of thermoplastics in power plant environments is a design
| |
| -driven criterion. The staff further noted that thermoplastic material is impervious and, once selected for the environment, will not have any significant age
| |
| -related Aging Management Review Results 3-440 degradation. The staff reviewed the associated items in the LRA and confirmed that no aging effect is applicable for this component, material, and environment combination because there is no indication in the industry that polymers or thermoplastics exposed to an internal or external condensation environment have any aging effects requiring management. Additionally, the generally low operating temperatures and historically good chemical resistance data for polymer components, combined with a lack of historically negative operating experience, indicate that polymers are not likely to experience any degradation from the non
| |
| -aggressive condensation environment.
| |
| In LRA Tables 3.3.2
| |
| -4, 3.3.2-11, 3.3.2-26, and 3.3.2
| |
| -37, the applicant stated that for polymeric piping, piping components, piping elements, and filter housings exposed to raw water environment, there is no aging effect, and no AMP is proposed. The AMR items cite generic Note F. These items also cite plant
| |
| -specific Notes 1 or 2. Plant
| |
| -specific Note 2 states the following:
| |
| Unlike metals, polymers do not display corrosion rates. Rather than depending on an oxide layer for protection, they depend on chemical resistance to the environment to which they are exposed. The plastic is either completely resistant to the environment or it deteriorates. Therefore, acceptability for the use of polymers within a given environment is a design driven criterion. Once the appropriate material is chosen, the system will have no aging effects. This is consistent with plant operating experience.
| |
| The staff reviewed the associated items in the LRA. The staff noted that polymer degradation occurs when it is exposed to high temperature or continuously exposed to ultraviolet rays and some chemicals. LRA Table 3.0
| |
| -1 defines raw water and states that it may contain contaminants including oil and boric acid, depending on the location, as well as originally treated water that is not monitored by a chemistry program. The staff also noted that it is, therefore, possible that these polymeric components could be exposed to an environment of raw water that includes oil, microorganisms, or other chemicals and, therefore, could potentially have an aging effect of cracking or blistering. By letter dated January 5, 2011, the staff issued RAI 3.3.2.3.4
| |
| -1, requesting that the applicant state why polymeric components in LRA Tables 3.3.2
| |
| -4 and 3.3.2
| |
| -26, exposed to a raw water environment as defined in LRA Table 3.0-1, will not exhibit any aging effects that require management.
| |
| In its response dated February 3, 2011, the applicant stated that the instrument element in LRA Table 3.3.2
| |
| -4 is manufactured from PVDF, which is a specialty plastic material in the fluoropolymer family and is used generally in applications requiring the highest purity, strength, and resistance to solvents, acids, bases, and heat. The applicant also stated that the material is rugged and unusually resistant to many chemical solvents, bases, and acids. The applicant further stated that the instrument element is correctly identified as no aging management required. The staff reviewed the applicant's response and confirmed that no aging effect is applicable for this component, material, and environment combination because the EPRI Non
| |
| -Class 1 Mechanical Implementation Guideline and Mechanical Tools Technical Report, Revision 4, states that PVDF is highly corrosion resistant and shows no effect in acids or alkalies. It also shows that PVDF is resistant to strong acids and organic solvents and has a continuous heat resistance of 300 °F.
| |
| | |
| Aging Management Review Results 3-441 For the filter housing, the applicant responded that it had inadvertently listed the material as polymer (PVC), and this strainer had been replaced with a Hastealloy strainer, which is a nickel
| |
| -alloy material. The staff's evaluation of nickel alloy in an internal environment of raw water is documented in SER Section 3.3.2.1.16. The staff's evaluation of nickel alloy in an external environment of condensation is documented in SER Section 3.3.2.3.15.
| |
| The applicant further stated that, in Table 3.3.2
| |
| -4, piping and fittings were inadvertently shown as polymer (PVC). The applicant stated that although there is polymer (PVC) piping in the chlorination system, none of it is within the scope of license renewal. Therefore, in Table 3.3.2-4, on page 3.3
| |
| -190, the applicant deleted these items. The staff finds the applicant's deletion of these AMR lines from LRA Table 3.3.2
| |
| -4 acceptable because the components are not within the scope of license renewal.
| |
| The applicant stated that in LRA Table 3.3.2
| |
| -26, the applicable PVC piping and valves ar e associated with the sump pumps in the intake and discharge transition structures. The applicant also stated that these sump pumps collect seawater leakage from circulating water and service water system piping and components in those buildings as well as groundwater in
| |
| -leakage and condensation in the building, and there are no contaminants, including oil and boric acid, normally found in sumps that would result in an aging effect requiring management. The staff reviewed the applicant's response and confirmed that no aging effect is applicable for this component, material, and environment combination because the EPRI Non
| |
| -Class 1 Mechanical Implementation Guideline and Mechanical Tools Technical Report, Revision 4, states that polymers such as PVC are resistant to seawater environments up to temperatures of 150 °F. The staff noted that UFSAR Table 9.2
| |
| -2 states that the design temperature of components in the service water systems is 200 °F; however, given that these components are associated with sump pumps, it is not expected that normal operating temperature of the in
| |
| -scope piping would exceed 150 °F.
| |
| Based on its review, as described above, the staff's concern described in RAI 3.3.2.3.4
| |
| -1 is resolved.
| |
| The staff reviewed the associated items in the LRA and confirmed that no aging effect is applicable for these component, material, and environment combinations because polymers such as PVDF, PVC, and polypropylene are highly resistant to solvents, acids, and bases, which is consistent with industry operating experience.
| |
| The staff's evaluation for glass piping elements exposed to air
| |
| -with borated water leakage (external) with no AERM and no recommended AMP, citing generic Note G, is documented in Section 3.3.2.3.3. Subsequent to the issuance of the SER with Open Items, by letter of March 5, 2014, the applicant amended the LRA to include metallic components with internal coatings exposed to fuel oil and raw water. The staff's evaluation of the AMR for these components is listed below.
| |
| Metallic Components with Internal Coatings Exposed to Fuel Oil and Raw Water. The staff's evaluation of internally coated metallic piping, fittings, and tanks exposed to fuel oil and raw water, which will be managed for loss of coating integrity by the Open
| |
| -Cycle Cooling Water System, Fire Water System, Fuel Oil Chemistry, and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Programs and are associated with generic Note G, is documented in SER Section 3.3.2.3.1, Auxiliary Boiler.
| |
| | |
| Aging Management Review Results 3-442 On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR result of material, environment, and AMP combinations not addressed in the GALL Report. The staff finds that the applicant 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 for the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.3.5 Containment Air Handling System
| |
| -Aging Management Evaluation
| |
| -LRA Table 3.3.2-5 The staff reviewed LRA Table 3.3.2
| |
| -5, which summarizes the results of AMR evaluations for the containment air handling system component groups.
| |
| In LRA Tables 3.3.2
| |
| -5 and 3.3.2
| |
| -7, the applicant stated that copper
| |
| -alloy heat exchanger components (cooling coil and cooling coil fins) exposed to condensation (external) are being managed for reduction in heat transfer by the External Surfaces Monitoring Program. The AMR items cite generic Note G. The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination. The GALL Report, item VII.F1
| |
| -16, states that copper
| |
| -alloy components exposed to condensation are susceptible to loss of material, which is addressed in other AMR items. Additionally, the function of the components of interest is to provide heat transfer; therefore, any accumulation of dirt, debris, or scale would prevent the component from performing its intended function, which is addressed in these AMR items.
| |
| The staff's evaluation of the applicant's External Surfaces Monitoring Program is documented in SER Section 3.0.3.2.14. The staff noted that the External Surfaces Monitoring Program includes visual inspections of the external surfaces of components subject to an AMR to identify the aging effect of reduction of heat transfer. The staff finds that the applicant's proposal to manage aging using the External Surfaces Monitoring Program is acceptable because the program uses periodic visual inspections that would identify corrosion discoloration and accumulation of dirt, scale, or debris indicative of fouling and, thus, detect a reduction in heat transfer.
| |
| In LRA Tables 3.3.2-5, 3.3.2-6, 3.3.2-7, 3.3.2-8, 3.3.2-18, and 3.3.2
| |
| -28, the applicant stated that the elastomer flexible connectors exposed to air with borated water leakage (external) are being managed for loss of material by the External Surfaces Monitoring Program. The AMR items cite generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination because the GALL Report, item VII.A3
| |
| -1, indicates that elastomers are susceptible to hardening and loss of strength due to elastomer degradation when exposed to treated borated water, which is addressed in other AMR items. The applicant also identified that the material is subject to loss of material when exposed to the environment of interest, air with borated water leakage, which is addressed the AMR items.
| |
| The staff's evaluation of the applicant's External Surfaces Monitoring Program is documented in SER Section 3.0.3.2.14. The staff noted that the applicant's program includes non
| |
| -visual examinations, such as scratching, to determine if scale or residues are present. These Aging Management Review Results 3-443 examinations also determine if there is a breakdown of material, bending, or folding of the elastomer to detect cracking that initiates at the surface, stretching, and pressing to determine the resistance of the material to hardening effects, and pressing to gauge the materials resiliency to maintain its strength. The staff finds that the applicant's proposal to manage aging using the External Surfaces Monitoring Program acceptable because the program includes periodic visual inspections as well as non
| |
| -visual tactile examinations to detect loss of material from the component.
| |
| The staff's evaluation for elastomer flexible connectors and flexible hose exposed to air with borated water leakage (external), which are being managed for hardening and loss of strength by the External Surfaces Monitoring Program citing generic Note G, is documented in SER Section 3.3.2.3.3.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.3.6 Containment Air Purge System
| |
| -Aging Management Evaluation
| |
| -LRA Table 3.3.2-6 The staff reviewed LRA Table 3.3.2
| |
| -6, which summarizes the results of AMR evaluations for the containment air purge system component groups.
| |
| The staff's evaluation for elastomer flexible connectors and flexible hose exposed to air with borated water leakage (external), which are being managed for hardening and loss of strength by the External Surfaces Monitoring Program citing generic Note G, is documented in SER Section 3.3.2.3.3.
| |
| The staff's evaluation for elastomer flexible connectors exposed to air with borated water leakage (external), which are being managed for loss of material by the External Surfaces Monitoring Program citing generic Note G, is documented in SER Section 3.3.2.3.5.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.3.7 Containment Enclosure Air Handling System
| |
| -Aging Management Evaluation
| |
| - LRA Table 3.3.2
| |
| -7 The staff reviewed LRA Table 3.3.2
| |
| -7, which summarizes the results of AMR evaluations for the containment enclosure air handling system component groups.
| |
| The staff's evaluation for elastomer flexible connectors and flexible hose exposed to air with borated water leakage (external), which are being managed for hardening and loss of strength by the External Surfaces Monitoring Program citing generic Note G, is documented in SER Section 3.3.2.3.3.
| |
| | |
| Aging Management Review Results 3-444 The staff's evaluation for copper
| |
| -alloy heat exchanger components exposed to condensation (external), which are being managed for reduction in heat transfer due to fouling by the External Surfaces Monitoring Program citing generic Note G, is documented in Section 3.3.2.3.5.
| |
| The staff's evaluation for elastomer flexible connectors exposed to air with borated water leakage (external), which are being managed for loss of material by the External Surfaces Monitoring Program citing generic Note G, is documented in SER Section 3.3.2.3.5.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.3.8 Containment Online Purge System
| |
| -Aging Management Evaluation
| |
| -LRA Table 3.3.2-8 The staff reviewed LRA Table 3.3.2
| |
| -8, which summarizes the results of AMR evaluations for the containment online purge system component groups.
| |
| The staff's evaluation for elastomer flexible connectors and flexible hose exposed to air with borated water leakage (external), which are being managed for hardening and loss of strength by the External Surfaces Monitoring Program citing generic Note G, is documented in SER Section 3.3.2.3.3.
| |
| The staff's evaluation for elastomer flexible connectors exposed to air with borated water leakage (external), which are being managed for loss of material by the External Surfaces Monitoring Program citing generic Note G, is documented in SER Section 3.3.2.3.5.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.3.9 Control Building Air Handling System
| |
| -Aging Management Evaluation
| |
| -LRA Table 3.3.2-9 The staff reviewed LRA Table 3.3.2
| |
| -9, which summarizes the results of AMR evaluations for the control building air handling systems component groups.
| |
| The staff's evaluation for galvanized steel damper housing exposed to air
| |
| -outdoor (internal), which is being managed for loss of material by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program and cite generic Note G, is documented in SER Section 3.3.2.3.1.
| |
| The staff's evaluation for stainless steel bolting exposed to air
| |
| -indoor, which is being managed for loss of preload by the Bolting Integrity Program citing generic Note G, is documented in SER Section 3.3.2.3.2.
| |
| | |
| Aging Management Review Results 3-445 The staff's evaluation for glass piping elements, exposed to air
| |
| -with borated water leakage (external) with no AERM and no recommended AMP citing generic Note G, is documented in SER Section 3.3.2.3.3.
| |
| The staff's evaluation for polymer (PVC) piping and fittings and filter housing exposed to condensation (internal or external) environment, with no aging effect and no AMP proposed citing generic Note F, is documented in SER Section 3.3.2.3.4.
| |
| The staff's evaluation for polymer (PVC, PVDF, polypropylene, fluoropolymer, polycarbonate, plastic and polyolefin) piping, piping components, and piping elements, flexible hose, tanks, and instrument elements exposed to air
| |
| -indoor uncontrolled (internal or external) and air
| |
| -indoor controlled external environments, with no aging effect and no AMP proposed citing generic Note F, is documented in SER Section 3.3.2.3.4.
| |
| In LRA Table 3.3.2
| |
| -9, the applicant stated that elastomer flexible connectors exposed to air
| |
| -indoor controlled (internal) are being managed for hardening and loss of strength and loss of material with the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The AMR item cites generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination. The GALL Report, Table IX.C, states that elastomers are susceptible to hardening and loss of strength at temperatures over about 95 °F (35 °C) and when exposed to additional aging factors such as ozone, oxidation, and radiation. The staff noted that the environment of interest, air
| |
| -indoor controlled (internal), has the potential of being in the temperature range for elastomer susceptibility to aging. Additionally, the GALL Report, item VII.F1
| |
| -6, indicates that elastomer seals and components are susceptible to loss of material or wear when exposed to an air
| |
| -indoor uncontrolled (internal) environment. Therefore, the staff noted that the aging effects of concern are hardening, loss of strength, and loss of material, which are addressed in the AMR.
| |
| The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff finds the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program acceptable for the following reasons:
| |
| * The program includes periodic visual inspections performed during maintenance and surveillance activities which can identify localized discoloration and surface irregularities.
| |
| * The program includes non
| |
| -visual examinations such as scratching, which will screen for residues and breakdown of the material, and stretching and pressing, which will evaluate the material resiliency to determine if hardening and loss of strength or loss of material is occurring that could result in a loss of the component
| |
| -intended function.
| |
| In LRA Table 3.3.2
| |
| -9, the applicant stated that stainless steel instrumentation elements, piping and fittings, and valve bodies internally exposed to air
| |
| -outdoor are being managed for loss of material due to pitting and crevice corrosion with the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The AMR item cites generic Note G.
| |
| The staff reviewed the associated items in the LRA and noted that, even though stainless steel instrumentation elements, piping and fittings, and valve bodies exposed to air
| |
| -outdoor are not Aging Management Review Results 3-446 specifically addressed in the GALL Report, Table IX.C of the GALL Report states that stainless steel material is susceptible to a variety of aging effects and mechanisms, including loss of material due to pitting and crevice corrosion and cracking due to SCC. The staff noted that given the plant's proximity to the ocean, stainless steel instrumentation elements, piping and fittings, and valve bodies internally exposed to the air
| |
| -outdoor environment would be susceptible to cracking due to SCC. However, the staff noted that the applicant did not identify cracking due to SCC as an AERM for these components. By letter dated February 24, 2011, the staff issued RAI 3.3
| |
| -1, requesting that the applicant justify its management of this material, environment, AERM, and AMP combination.
| |
| In its response dated March 22, 2011, the applicant stated that SCC has been added as an aging mechanism for stainless steel components exposed to an air
| |
| -outdoor environment. The applicant added new AMR items to manage cracking using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The staff finds the applicant's response acceptable because the applicant modified the LRA to include cracking due to SCC as an applicable aging effect for stainless steel components exposed to outdoor air and will use either magnified visual inspections or ultrasonic inspections, which are capable of detecting cracking. The staff's concern described in RAI 3.3
| |
| -1 is resolved.
| |
| The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff finds the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program acceptable for the following reasons:
| |
| * The program includes periodic visual inspections performed during maintenance and surveillance activities, which can identify localized discoloration and surface irregularities such as rust, scale or deposits, and surface pitting.
| |
| * The program includes either magnified visual inspection or ultrasonic inspection to determine if material degradation is occurring that could result in a loss of the component-intended function.
| |
| In LRA Table 3.3.2
| |
| -9, the applicant stated that for copper
| |
| -alloy piping, fittings, and valves exposed to air
| |
| -indoor controlled (external), there is no aging effect, and no AMP is proposed. The AMR items cite generic Note G and plant
| |
| -specific Notes 11 and 12. Notes 11 and 12 state that NUREG
| |
| -1801 does not include air
| |
| -indoor controlled for copper alloy and copper alloy greater than 15 percent zinc components. Similar to V.F
| |
| -3 for copper alloy and copper alloy greater than 15
| |
| -percent zinc in air
| |
| -indoor uncontrolled, there are no aging effects for copper alloy and copper alloy greater than 15
| |
| -percent zinc in air
| |
| -indoor controlled. The staff reviewed the associated items in the LRA and confirmed that no aging effect is applicable for this component, material, and environment combination. GALL Report item V.F.3 for copper alloy exposed to uncontrolled indoor air bounds the consideration for these components in controlled indoor air, and item V.F.3 states there are no aging effects for copper
| |
| -alloy components in uncontrolled indoor air.
| |
| In LRA Table 3.3.2
| |
| -9, the applicant stated that for stainless steel valve bodies, thermowells, piping and fittings, and instrumentation elements exposed to air
| |
| -indoor controlled (external), there is no aging effect, and no AMP is proposed. The AMR items cite generic Note G and plant-specific Note 10, which states that NUREG
| |
| -1801 does not include air
| |
| -indoor controlled for Aging Management Review Results 3-447 stainless steel components. However, similar to VII.J
| |
| -15 for stainless steel in air
| |
| -indoor uncontrolled, there are no aging effects for stainless steel in air
| |
| -indoor controlled.
| |
| The staff reviewed the associated items in the LRA and confirmed that no aging effect is applicable for this component, material, and environment combination because controlled indoor air contains less moisture than uncontrolled indoor air; therefore, uncontrolled indoor air can be considered a bounding environment for components exposed to controlled indoor air. The GALL Report states that stainless steel components exposed to uncontrolled indoor air do not have any aging effects, and no AMP is recommended.
| |
| In LRA Tables 3.3.2
| |
| -9, 3.3.2-12, 3.3.2-29, and 3.3.2
| |
| -30 the applicant stated that for glass piping elements exposed to closed
| |
| -cycle cooling water (internal) or gas (internal), there is no aging effect, and no AMP is proposed. The AMR items cite generic Note G. The staff reviewed the associated items in the LRA and confirmed that no aging effect is applicable for this component, material, and environment combination because the GALL Report has multiple AMR Items that state that for an environment of indoor uncontrolled air, raw water, or treated water, there is no AERM and no recommended AMP, and the closed
| |
| -cycle cooling water (internal) or gas (internal) environment is no more severe than the raw water or indoor uncontrolled air environment already addressed in the GALL Report.
| |
| In LRA Tables 3.3.2
| |
| -9, 3.3.2-17, and 3.3.2
| |
| -40, the applicant stated that the stainless steel filter element, piping and fittings, valve body, expansion joint, and filter housing exposed to air
| |
| -outdoor (external) are being managed for loss of material by the External Surfaces Monitoring Program. The AMR items cite generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination. Even though stainless steel exposed to air
| |
| -outdoor (external) is not specifically addressed in the GALL Report, Table IX.C of the GALL Report states that stainless steels are susceptible to loss of material due to pitting and crevice corrosion and cracking due to SCC. The staff noted that the environment of interest, air
| |
| -outdoor (external) would be expected to contain higher levels of chlorides due to the site's relative proximity to the ocean, which are known to induce SCC. By letter dated February 24, 2011 (ADAMS Accession No. ML110260266), the staff issued RAI 3.3-1, requesting that the applicant provide additional information on why atmospheric chloride
| |
| -induced SCC is not considered to be an applicable aging effect for stainless steel components exposed to outdoor
| |
| -air and explain how SCC will be managed if it is determined to be an applicable aging affect.
| |
| In its response dated March 22, 2011 (ADAMS Accession No. ML110830045), the applicant stated that SCC has been added as an aging mechanism for stainless steel components exposed to air-outdoor environment. The applicant added a new item to manage cracking by either the External Surfaces Monitoring Program or the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The staff finds the applicant's response acceptable because the applicant has modified the LRA to do the following:
| |
| * include SCC as an applicable aging effect for stainless steel components exposed to outdoor-air containing high levels of chloride
| |
| * include either magnified visual inspection or ultrasonic inspection in the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program
| |
| | |
| Aging Management Review Results 3-448
| |
| * include SCC as an aging effect to be managed by the External Surfaces Monitoring Program, which includes visual inspections that is a capable technique to detect SCC The staff's concern described in RAI 3.3
| |
| -1 is resolved.
| |
| The staff's evaluations of the applicant's External Surfaces Monitoring Program and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program are documented in SER Sections 3.0.3.2.14 and 3.0.3.2.15, respectively. The staff finds that the applicant's proposal to manage aging using the External Surfaces Monitoring Program and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program acceptable because the programs use periodic or opportunistic visual inspections that would detect loss of material and SCC prior to loss of component
| |
| -intended function.
| |
| In LRA Table 3.3.2-9, the applicant stated that the elastomer flexible connectors exposed to air
| |
| -indoor controlled (external) are being managed for hardening and loss of strength and loss of material by the External Surfaces Monitoring Program. The AMR item cites generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination. The GALL Report, item VII.F1
| |
| -7, states that elastomers exposed to indoor air are susceptible to hardening and loss of strength due to elastomer degradation, and GALL Report item VII.F1
| |
| -5 states that elastomers exposed to indoor air are susceptible to loss of material due to wear, both of which are addressed in the AMR items.
| |
| The staff's evaluation of the applicant's External Surfaces Monitoring Program is documented in SER Section 3.0.3.2.14. The staff noted that the applicant's program includes non
| |
| -visual examinations, such as scratching, to determine if scale or residues are present or determine if there is a breakdown of material, bending, or folding of the elastomer to detect cracking that initiates at the surface. The program also includes stretching and pressing to determine the resistance of the material to hardening effects and pressing to gauge the materials resiliency to maintain its strength. The staff finds that the applicant's proposal to manage aging using the External Surfaces Monitoring Program acceptable because the program uses periodic visual inspections as well as non
| |
| -visual tactile examinations, which are capable of detecting loss of material and hardness and loss of strength.
| |
| In LRA Table 3.3.2
| |
| -9, the applicant stated that aluminum heat exchanger components exposed to condensation (external) are being managed for reduction in heat transfer by the External Surfaces Monitoring Program. The AMR item cites generic Note F.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effect for this component, material, and environment combination. The GALL Report, item VII.F1
| |
| -14, states that aluminum components exposed to condensation are susceptible to loss of material, which is addressed in another AMR item. Additionally, the components of interest function in a capacity to provide heat transfer and therefore any accumulation of dirt, debris, or scale could prevent the component from performing its intended function, which is addressed in this AMR item.
| |
| In LRA Tables 3.3.2
| |
| -9 and 3.3.2
| |
| -12, the applicant stated that aluminum heat exchanger components exposed to air
| |
| -indoor uncontrolled (external) are being managed for reduction in Aging Management Review Results 3-449 heat transfer by the External Surfaces Monitoring Program. The AMR item cites generic Note F. The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination for the following reasons:
| |
| * The GALL Report, item V.F
| |
| -2, states that aluminum components exposed to air have no aging effects requiring management.
| |
| * The components of interest function in a capacity to provide heat transfer; therefore, any accumulation of dirt, debris, or scale could prevent the component from performing its intended function, which is addressed in this AMR item.
| |
| The staff's evaluation of the applicant's Inspection of External Surfaces Monitoring Program is documented in SER Section 3.0.3.2.14. The staff finds that the applicant's proposal to manage aging using the External Surfaces Monitoring Program acceptable because the program uses periodic visual inspections that would identify corrosion discoloration and accumulation of dirt, scale, or debris indicative of fouling and, thus, detect any reduction in heat transfer prior to loss of the component's intended function.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.3.10 Demineralized Water System
| |
| -Aging Management Evaluation
| |
| -LRA Table 3.3.2-10 The staff reviewed LRA Table 3.3.2
| |
| -10, which summarizes the results of AMR evaluations for the demineralized water system component groups.
| |
| The staff's evaluation for stainless steel bolting, exposed to air
| |
| -indoor and being managed for loss of preload by the Bolting Integrity Program citing generic Note G, is documented in SER Section 3.3.2.3.2.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.3.11 Dewatering System
| |
| -Aging Management Evaluation
| |
| -LRA Table 3.3.2
| |
| -11 The staff reviewed LRA Table 3.3.2
| |
| -11, which summarizes the results of AMR evaluations for the dewatering system component groups.
| |
| | |
| Aging Management Review Results 3-450 The staff's evaluation for stainless steel bolting, exposed to air
| |
| -indoor and being managed for loss of preload by the Bolting Integrity Program citing generic Note G, is documented in SER Section 3.3.2.3.2.
| |
| The staff's evaluation for glass piping elements, exposed to air
| |
| -with borated water leakage (external) with no AERM and no recommended AMP citing generic Note G, is documented in SER Section 3.3.2.3.3.
| |
| The staff's evaluation for polymer piping, piping components, piping elements, and filter housing exposed to raw water environment, with no aging effect and no AMP proposed citing generic Note F, is documented in SER Section 3.3.2.3.4.
| |
| The staff's evaluation for elastomer flexible connectors and flexible hose exposed to air with borated water leakage (external), which are being managed for hardening and loss of strength by the External Surfaces Monitoring Program citing generic Note G, is documented in SER Section 3.3.2.3.3.
| |
| The staff's evaluation for polymer (PVC, PVDF, polypropylene, fluoropolymer, polycarbonate, plastic and polyolefin) piping, piping components, piping elements, flexible hose, tanks, and instrument elements exposed to air
| |
| -indoor uncontrolled (internal or external) and air
| |
| -indoor controlled external environments, with no aging effect and no AMP proposed citing generic Note F, is documented in SER Section 3.3.2.3.4.
| |
| In LRA Tables 3.3.2
| |
| -11, 3.3.2-20, and 3.3.2
| |
| -35, the applicant stated that for polymer (PVC, polypropylene, fluoropolymer, polycarbonate, polyolefin, and plastic) piping, piping components and piping elements, tank, and flexible hose exposed to air with borated water external environment, there is no aging effect, and no AMP is proposed. The AMR items cite generic Note F. These items also cite plant
| |
| -specific Notes 1 or 2. Plant
| |
| -specific Note 2 states the following:
| |
| Unlike metals, polymers do not display corrosion rates. Rather than depending on an oxide layer for protection, they depend on chemical resistance to the environment to which they are exposed. The plastic is either completely resistant to the environment or it deteriorates. Therefore, acceptability for the use of polymers within a given environment is a design driven criterion. Once the appropriate material is chosen, the system will have no aging effects. This is consistent with plant operating experience.
| |
| The staff noted that, as identified in Engineering Materials Handbook
| |
| -Engineering Plastics , American Society for Metals International, Copyright 1988, rigid polymers are unaffected by water, concentrated alkalis, non
| |
| -oxidizing acids, oils, ozone, sunlight, or humidity changes. The staff also noted that, unlike metals, thermoplastics do not display corrosion rates, and rather than depend on an oxide layer for protection, they depend on chemical resistance to the environments to which they are exposed, and the use of thermoplastics in power plant environments is a design
| |
| -driven criterion. The staff further noted that thermoplastic materials are impervious and, once selected for the environment, will not have any significant age
| |
| -related degradation. The staff reviewed the associated items in the LRA and confirmed that no aging effect is applicable for this component, material, and environment combination because there is no indication in the industry that polymers or thermoplastics exposed to an internal or external indoor air environment have any aging effects requiring management. Additionally, the Aging Management Review Results 3-451 generally low operating temperatures and historically good chemical resistance data for polymer components, combined with a lack of historically negative operating experience, indicate that polymers are not likely to experience any degradation from the non
| |
| -aggressive air with borated water environment.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.3.12 Diesel Generator
| |
| -Aging Management Evaluation
| |
| -LRA Table 3.3.2
| |
| -12 The staff reviewed LRA Table 3.3.2
| |
| -12, which summarizes the results of AMR evaluations for the diesel generator system component groups.
| |
| The staff's evaluation for aluminum flame arrestor and piping and fittings exposed to air-outdoor (external), which are being managed for loss of material by the External Surfaces Monitoring Program citing generic Note G, is documented in SER Section 3.3.2.3.1.
| |
| The staff's evaluation for stainless steel bolting exposed to air
| |
| -indoor, which is being managed for loss of preload by the Bolting Integrity Program citing generic Note G, is documented in SER Section 3.3.2.3.2.
| |
| The staff's evaluation for elastomer flexible hoses exposed to fuel oil or lubricating oil (internal), which are being managed for hardening and loss of strength by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program and cite generic Note G, is documented in SER Section 3.3.2.3.3.
| |
| The staff's evaluation for glass piping elements exposed to closed
| |
| -cycle cooling water (internal) or gas (internal), which cite generic Note G, is documented in SER Section 3.3.2.3.9.
| |
| The staff's evaluation for aluminum heat exchanger components exposed to air
| |
| -indoor uncontrolled (external), which are being managed for reduction in heat transfer by the External Surfaces Monitoring Program and cite generic Note F, is documented in SER Section 3.3.2.3.9.
| |
| In LRA Table 3.3.2
| |
| -12, the applicant stated that the aluminum heat exchanger components (DG-MM-888A and DG-MM-888 after cooler tubes) exposed to condensation (internal) are being managed for reduction of heat transfer by the Compressed Air Monitoring Program. The AMR item cites generic Note F.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination because even though the GALL Report does not have aluminum heat exchangers exposed to condensation, heat exchangers are known to be susceptible to reduction of heat transfer aging issues. The staff's evaluation of the applicant's Compressed Air Monitoring Program is documented in SER Section 3.0.3.2.6. The staff finds the applicant's proposal to manage aging using the
| |
| | |
| Aging Management Review Results 3-452 Compressed Air Monitoring Program acceptable because the Compressed Air Monitoring Program includes visual inspection techniques that are capable of detecting reduction of heat transfer and annual testing to verify that the performance of the system is in accordance with its intended functions.
| |
| In LRA Tables 3.3.2
| |
| -12 and 3.3.2
| |
| -15, the applicant stated that elastomer flexible hoses exposed to closed-cycle cooling water (internal) are being managed for hardening and loss of strength with the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The AMR items cite generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination. The GAL L Report, Table IX.C, states that elastomers are susceptible to hardening and loss of strength at temperatures over about 95 °F (35 °C) and when exposed to additional aging factors such as ozone, oxidation, and radiation. The staff noted that the environment of interest, closed
| |
| -cycle cooling water (internal), has the potential of being in the temperature range for elastomer susceptibility to aging; therefore, the aging effect of concern is hardening and loss of strength, which is addressed in the AMR.
| |
| The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff finds the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program acceptable for the following reasons:
| |
| * The program includes periodic visual inspections performed during maintenance and surveillance activities that can identify localized discoloration and surface irregularities.
| |
| * The program includes non
| |
| -visual examinations, such as scratching, which will screen for residues and breakdown of the material, and stretching and pressing which will evaluate the material resiliency to determine if hardening and loss of strength is occurring that could result in a loss of the component
| |
| -intended function.
| |
| In LRA Table 3.3.2
| |
| -12, the applicant stated that the elastomer flexible hose exposed to condensation (internal) is being managed for hardening and loss of strength by the Compressed Air Monitoring Program. The AMR item cites generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination. Even though elastomer materials exposed to condensation are not in the GALL Report for hardening and loss of strength, GALL Report, Tables IX.C and IX.E, indicate that elastomers are susceptible to hardening and loss of strength. It was unclear to the staff how the applicant will appropriately manage the hardening and loss of strength of the elastomer components because the indications of aging are substantially different from those of steel or stainless steel, which the GALL Report references. By letter dated January 5, 2011, the staff issued RAI 3.3.2.12
| |
| -1, requesting that the applicant provide details on the additional inspection methods to be used to ensure that the AMP will adequately address potential aging effects of the elastomer materials.
| |
| In its response dated February 3, 2011, the applicant stated that the diesel generator air compressors are replaced every 10 years. The applicant stated that during this routine maintenance, the flexible hoses on these compressors will also be replaced.
| |
| The applicant Aging Management Review Results 3-453 stated that because the flexible hoses are periodically replaced, they are not subject to an AMR. The applicant also committed under the Compressed Air Monitoring Program to replace the flexible hoses every 10 years and within 10 years of the period of extended operation. This response is acceptable because the applicant committed to replace the flexible hoses under the Compressed Air Monitoring Program, Commitment 61, making them subject to replacement, which does not need to be included in the license renewal process under 10 CFR 54.21(a)(1)(ii). The staff's concern described in RAI 3.3.2.12
| |
| -1 is resolved.
| |
| In LRA Table 3.3.2
| |
| -12, the applicant stated that for aluminum filter housings and valve bodies exposed to dried air (internal), there is no aging effect, and no AMP is proposed. The AMR items cite generic Note G. Items associated with aluminum piping, fittings, and valves in Tables 3.3.2-12 and 3.3.2
| |
| -20 cite plant
| |
| -specific notes, which state aluminum exposed to dried air environment does not have any applicable aging effect and provide an industry reference as a technical basis.
| |
| The staff reviewed the associated items in the LRA and confirmed that no aging effect is applicable for this component, material, and environment combination because, even though aluminum exposed to dried air is not specifically addressed in the GALL Report, the GALL Report, item V.F.2, states that aluminum piping, components, and elements exposed to uncontrolled indoor air have no aging effects or aging mechanisms. The staff considers dried air to be less aggressive than uncontrolled indoor air since moisture would not be available to cause loss of material due to pitting.
| |
| Subsequent to the issuance of the SER with Open Items, by letter of March 5, 2014, the applicant amended the LRA to include metallic components with internal coatings exposed to fuel oil and raw water. The staff's evaluation of the AMR for these components is listed below.
| |
| Metallic Components with Internal Coatings Exposed to Fuel Oil and Raw Water. The staff's evaluation of internally coated metallic piping, fittings, and tanks exposed to fuel oil and raw water, which will be managed for loss of coating integrity by the Open
| |
| -Cycle Cooling Water System, Fire Water System, Fuel Oil Chemistry, and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Programs, and which are associated with generic Note G, is documented in SER Section 3.3.2.3.1, Auxiliary Boiler.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.3.13 Diesel Generator Air Handling System
| |
| -Aging Management Evaluation
| |
| -LRA Table 3.3.2-13 The staff reviewed LRA Table 3.3.2
| |
| -13, which summarizes the results of AMR evaluations for the diesel generator air handling system component groups.
| |
| The staff's review did not find any items indicating plant
| |
| -specific Notes F
| |
| -J, whereby the combination of component type, material, environment, and AERM does not correspond to an item in the GALL Report.
| |
| | |
| Aging Management Review Results 3-454 The staff's evaluation of the items with Notes A
| |
| -E is documented in SER Section 3.3.2.1.
| |
| 3.3.2.3.14 Emergency Feed Water Pump House Air Handling System
| |
| -Aging Management Evaluation
| |
| -LRA Table 3.3.2
| |
| -14 The staff reviewed LRA Table 3.3.2
| |
| -14, which summarizes the results of AMR evaluations for the emergency feed water pump house air handling system component groups.
| |
| The staff's review did not find any items indicating plant
| |
| -specific Notes F
| |
| -J, whereby the combination of component type, material, environment, and AERM does not correspond to an item in the GALL Report.
| |
| The staff's evaluation of the items with Notes A
| |
| -E is documented in SER Section 3.3.2.1.
| |
| 3.3.2.3.15 Fire Protection System
| |
| -Aging Management Evaluation
| |
| -LRA Table 3.3.2
| |
| -15 The staff reviewed LRA Table 3.3.2
| |
| -15, which summarizes the results of AMR evaluations for the fire protection system component groups.
| |
| The staff's evaluation for elastomer flexible hose exposed to fuel oil or lubricating oil (internal), which are being managed for hardening and loss of strength by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program and cite generic Note G, is documented in SER Section 3.3.2.3.3.
| |
| The staff's evaluation for elastomer flexible hose exposed to closed
| |
| -cycle cooling water (internal), which are being managed for hardening and loss of strength by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program and cite generic Note G, is documented in SER Section 3.3.2.3.12 The staff's evaluation for fiberglass piping and fittings exposed to raw water (internal) with no AERM and no recommended AMP, citing generic Note F, is documented in Section 3.3.2.3.4.
| |
| In LRA Table 3.3.2
| |
| -15, the applicant stated that the stainless steel heat exchanger components exposed to steam are being managed for reduction of heat transfer by the Water Chemistry Program. The AMR item cites generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination. Even though stainless steel exposed to steam, by this specific aging effect, is not specifically addressed in the GALL Report, Chapter V of the GALL Report states that stainless steel heat exchangers are susceptible to reduction of heat transfer in other aqueous environments. In addition, the GALL Report also states that stainless steel exposed to steam can undergo loss of material or cracking, which the applicant has included in other AMR items. However, it was not clear to staff how the Water Chemistry Program alone would ensure that reduction of heat transfer is appropriately managed. Typically, for reduction of heat transfer, a Water Chemistry Program along with an Inspection Program is used to manage this aging effect. By letter dated January 5, 2011, the staff issued RAI 3.3.2.15
| |
| -1, requesting that the applicant justify how the Water Chemistry Program alone is sufficient to determine that steam generator tubes are not affected by reduction of heat transfer when exposed to reactor coolant.
| |
| | |
| Aging Management Review Results 3-455 In its response dated August 11, 2011, the applicant stated that the steam environment listed in LRA Table 3.3.2
| |
| -15, for FP
| |
| -E-46 and FP-E-47, is developed from potable water. The applicant stated that because the steam environment listed is potable water converted to steam, it is not subject to the Water Chemistry Program. The applicant further stated that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is more appropriate and will be used to manage the heat exchanger reduction of heat transfer. The applicant also stated that it has preventive maintenance activities already in place to clean and inspect the external surfaces of the heat exchanger tubes for FP
| |
| -E-46 and FP-E-47 on a frequency of approximately every 4 years, and these two items changed from a generic Notes C to G. The staff finds the applicant's response acceptable because the applicant modified the LRA to use inspection programs to identify aging in the heat exchanger tubes, which is consistent with the guidance in the GALL Report. The staff's concern described in RAI 3.3.2.15-1 is resolved.
| |
| In LRA Table 3.3.2
| |
| -15, the applicant stated that steel and stainless steel bolting exposed to soil is being managed for loss of preload and loss of material by the Bolting Integrity Program. The AMR item cites generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination. Even though steel and stainless steel bolting exposed to soil are not specifically addressed in the GALL Report, Table IX.E of the GALL Report states that loss of preload can occur independent of environmental conditions because it can be caused by thermal or mechanical effects. Similarly, a soil environment as indicated in the GALL Report is known to cause loss of material.
| |
| The staff's evaluation of the applicant's Bolting Integrity Program is documented in SER Section 3.0.3.1.7. While there is no AMR for loss of preload or loss of material of steel and stainless steel bolting exposed to soil in the auxiliary systems, the GALL Report has items for loss of preload and loss of material of bolting managed by the Bolting Integrity Program. The staff finds the applicant's proposal to manage aging using the Bolting Integrity Program acceptable because Bolting Integrity Program inspects the bolting to verify that the aging effect, loss of preload, will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation. Additionally, the Bolting Integrity Program is supplemented by the Buried Piping and Tanks Inspection Program, which will visually inspect for leakage when bolted joints are excavated.
| |
| In LRA Table 3.3.2
| |
| -15, the applicant stated that the steel and stainless steel bolting exposed to soil is being managed for loss of material by the Buried Piping and Tanks Inspection Program. The AMR item cites generic Note G.
| |
| The staff noted that LRA Table 3.3.2
| |
| -15 contains an item for the same component with an aging effect of loss of preload. The staff also noted that the "parameters monitored/inspected" program element of GALL Report AMP XI.M18, "Bolting Integrity," states that, "[s]pecifically, bolting for safety
| |
| -related pressure
| |
| -retaining components is inspected for leakage, loss of material, cracking, and loss of preload/loss of prestress. Bolting for other pressure-retaining components is inspected for signs of leakage." The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination because, in addition to managing loss of material, the applicant is managing the only other aging effect by using the Bolting Integrity Program to Aging Management Review Results 3-456 manage loss of preload. The staff noted that GALL Report AMP XI.M.18 does not recommend managing cracking for nonsafet y-related bolting.
| |
| The staff's evaluation of the applicant's Buried Piping and Tanks Inspection Program is documented in SER Section 3.0.3.3.1. The staff finds that the applicant's proposal to manage aging using the Buried Piping and Tanks Inspection Program is acceptable for the following reasons:
| |
| * The program includes preventive actions, such as external coatings and wrappings installed to industry standard practices and backfill that will not damage the bolting or coatings. Some systems are protected by a cathodic protection system.
| |
| * Periodic visual inspections will be performed starting 10 years prior to the period of extended operation and extend into both 10
| |
| -year periods during the period of extended operation to ensure that coatings remain intact or uncoated bolting has not degraded.
| |
| * Plant-specific operating experience will be used to inform inspection locations.
| |
| * Alternatives to direct visual inspection, such as pressure tests, are capable of detecting degradation of the bolted connection.
| |
| In LRA Table 3.3.2
| |
| -15, the applicant stated that fiberglass piping exposed to soil is being managed for cracking, blistering and change in material properties by the Buried Piping and Tanks Inspection Program. The AMR item cites generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination. Polymeric materials share many of the same aging effects as elastomers, and the applicant's proposed aging effects are the same as those applicable aging effects listed in GALL Report Table IX.F for elastomeric materials. The staff noted the additional aging effects listed in Table IX.F as follows:
| |
| * Aging effects of fatigue breakdown would evidence themselves in a similar manner to that of cracking.
| |
| * Abrasion from localized poor quality backfill would evidence itself as loss of material.
| |
| * If the soil contains chemicals that affect the polymeric material, the aging effect would be evidenced by loss of material.
| |
| * Weathering is not applicable in the soil environment.
| |
| The staff's evaluation of the applicant's Buried Piping and Tanks Inspection Program is documented in SER Section 3.0.3.3.1. The staff finds that the applicant's proposal to manage aging using the Buried Piping and Tanks Inspection Program is acceptable for the following reasons:
| |
| * The program includes the preventive action of ensuring that the quality of backfill will not damage the piping.
| |
| * Periodic visual inspections, including mechanical examination for evidence of changes in material properties, will be performed starting 10 years prior to the period of extended Aging Management Review Results 3-457 operation and extend into both 10
| |
| -year periods during the period of extended operation to ensure that the piping has not degraded.
| |
| * Plant-specific operating experience will be used to inform inspection locations.
| |
| * Alternatives to direct visual inspection such as pressure tests are capable of detecting degradation of the piping.
| |
| In LRA Tables 3.3.2
| |
| -15, 3.3.2-17, 3.3.2-36, 3.3.2-37, and 3.3.2
| |
| -40, the applicant stated that copper alloy and copper alloy with greater than 15
| |
| -percent zinc valve body, instrumentation element, nozzle, filter housing, and piping and fittings exposed to air
| |
| -outdoor (external) and nickel-alloy rupture disc, expansion joint, instrumentation element, orifice, and thermowell exposed to air
| |
| -outdoor (external) or condensation (external) are being managed for loss of material by the External Surfaces Monitoring Program. The AMR items cite generic Note G. The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination. The GALL Report, item VII.G
| |
| -9, states that copper alloys, including copper alloys with greater than 15
| |
| -percent zinc, exposed to condensation such as what could occur in an outdoor air environment, are susceptible to loss of material, which is addressed in this AMR item. While nickel
| |
| -alloy components exposed to condensation (external) are not specifically addressed in the GALL Report for item VII.C1
| |
| -13, it states that nickel alloys exposed to raw water are susceptible to loss of material, which is addressed in the AMR item.
| |
| The staff's evaluation of the applicant's External Surfaces Monitoring Program is documented in SER Section 3.0.3.2.14. The staff finds that the applicant's proposal to manage aging using the External Surfaces Monitoring Program acceptable because the program uses periodic visual inspections that would detect loss of material prior to loss of component
| |
| -intended function.
| |
| Metallic Components with Internal Coatings Exposed to Fuel Oil and Raw Water. By letter of March 5, 2014, the applicant amended the LRA to include metallic components with internal coatings exposed to fuel oil and raw water. The staff's evaluation of internally coated metallic piping, fittings, and tanks exposed to fuel oil and raw water, which will be managed for loss of coating integrity by the Open
| |
| -Cycle Cooling Water System, Fire Water System, Fuel Oil Chemistry, and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Programs, and which are associated with generic Note G, is documented in SER Section 3.3.2.3.1, Auxiliary Boiler.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.3.16 Fuel Handling System Aging Management Evaluation
| |
| -LRA Table 3.3.2
| |
| -16 The staff reviewed LRA Table 3.3.2
| |
| -16, which summarizes the results of AMR evaluations for the fuel handling system component groups.
| |
| | |
| Aging Management Review Results 3-458 The staff's evaluation for stainless steel bolting exposed to air-indoor, which is being managed for loss of preload by the Bolting Integrity Program citing generic Note G, is documented in SER Section 3.3.2.3.2.
| |
| The staff's evaluation for glass piping elements exposed to air
| |
| -with borated water leakage (external), with no AERM and no recommended AMP citing generic Note G, is documented in SER Section 3.3.2.3.3.
| |
| The staff's evaluation for elastomer flexible connectors and flexible hose exposed to air with borated water leakage (external), which are being managed for hardening and loss of strength by the External Surfaces Monitoring Program citing generic Note G, is documented in SER Section 3.3.2.3.3.
| |
| In LRA Tables 3.3.2-16 and 3.3.2
| |
| -35, the applicant stated that elastomer flexible hoses exposed to treated water (internal) are being managed for hardening and loss of strength with the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The AMR item cites generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination because the GALL Report, Table IX.C, states that elastomers are susceptible to hardening and loss of strength at temperatures over about 95 °F (35 °C) and when exposed to additional aging factors such as ozone, oxidation, and radiation. The staff noted that the environment of interest, treated water (internal) has the potential of being in the temperature range for elastomer susceptibility to aging; therefore, the aging effect of concern is hardening and loss of strength, which is addressed in the AMR.
| |
| The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff finds the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program acceptable for the following reasons:
| |
| * The program include periodic visual inspections performed during maintenance and surveillance activities, which can identify localized discoloration and surface irregularities.
| |
| * Non-visual examinations, such as scratching, which will screen for residues and breakdown of the material, and stretching and pressing, which will evaluate the material resiliency to determine if hardening and loss of strength are occurring that could result in a loss of the component
| |
| -intended function.
| |
| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
| |
| 3.3.2.3.17 Fuel Oil System
| |
| -Aging Management Evaluation
| |
| -LRA Table 3.3.2
| |
| -17 Aging Management Review Results 3-459 The staff reviewed LRA Table 3.3.2
| |
| -17, which summarizes the results of AMR evaluations for the fuel oil system component groups.
| |
| The staff's evaluation for steel bolting exposed to air
| |
| -outdoor, which is being managed for loss of preload by the Bolting Integrity Program citing generic Note G, is documented in SER Section 3.3.2.3.1.
| |
| The staff's evaluation for stainless steel piping and fittings, valve body, expansion joint, filter housing and tanks exposed to air
| |
| -outdoor (external), which are being managed for loss of material by the External Surfaces Monitoring Program citing generic Note G, is documented in SER Section 3.3.2.3.9.
| |
| The staff's evaluation for copper alloy and copper alloy with greater than 15
| |
| -percent zinc valve body, instrumentation element, nozzle, filter housing, and piping and fittings, and nickel
| |
| -alloy piping and fittings, valve body, expansion joint, and rupture disc exposed to air
| |
| -outdoor (external), which are being managed for loss of material by the External Surfaces Monitoring Program citing generic Note G, is documented in SER Section 3.3.2.3.15.
| |
| In LRA Tables 3.3.2
| |
| -17 and 3.3.2
| |
| -40, the applicant stated that the stainless steel bolting exposed to air
| |
| -outdoor is being managed for loss of material by the Bolting Integrity Program. The AMR item cites generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination. Even though stainless steel bolting exposed to air
| |
| -outdoor is not specifically addressed in the GALL Report, Table IX.C of the GALL Report states that stainless steel material is susceptible to a variety of aging effects and mechanisms, including loss of material due to pitting and crevice corrosion and cracking due to SCC. The staff noted that given the plant's proximity to the ocean, stainless steel bolting exposed to the outdoor air environment would be susceptible to SCC. However, the staff noted that the applicant did not identify SCC as an AERM for these components. By letter dated February 24, 2011, the staff issued RAI 3.3
| |
| -1, requesting that the applicant justify its management of this material, environment, AERM, and AMP combination.
| |
| In its response dated March 22, 2011, the applicant stated that SCC has been added as an aging mechanism for stainless steel components exposed to air
| |
| -outdoor environment. The applicant added a new item to manage cracking of bolts by the Bolting Integrity Program. The staff finds the applicant's response acceptable because the applicant modified the LRA to include cracking due to SCC as an applicable aging effect for stainless steel components exposed to outdoor
| |
| -air containing high levels of chloride and is managing SCC by the Bolting Integrity Program. The staff's concern described in RAI 3.3
| |
| -1 is resolved.
| |
| The staff's evaluation of the applicant's Bolting Integrity Program is documented in SER Section 3.0.3.1.7. While there is no AMR for stainless steel bolting exposed to air
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| -outdoor in the auxiliary system, the GALL Report has items for other material bolting exposed to air
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| -outdoor managed by the Bolting Integrity Program. The staff finds the applicant's proposal to manage aging using the Bolting Integrity Program acceptable because the Bolting Integrity Program inspects the bolting through periodic visual inspections to verify that the aging effect, loss of material and SCC, will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation; therefore, it is acceptable.
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| Aging Management Review Results 3-460 In LRA Tables 3.3.2
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| -17 and 3.3.2
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| -40, the applicant stated that the stainless steel boltin g exposed to air
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| -outdoor is being managed for loss of preload by the Bolting Integrity Program. The AMR item cites generic Note G.
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| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination. Even though stainless steel bolting exposed to air
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| -outdoor is not specifically addressed in the GALL Report, Table IX.E of the GALL Report states that loss of preload can occur independent of environmental conditions because it can be caused by thermal or mechanical effects. Additionally, Table IX.C of the GALL Report states that stainless steel material is susceptible to a variety of aging effects and mechanisms, including loss of material due to pitting and crevice corrosion and cracking due to SCC. The staff noted that the applicant addressed loss of material in additional items for each of these components and the staff evaluated SCC as documented in SER Section 3.3.2.3.17 for this component, material, and environment combination; therefore, the aging effect of concern is loss of preload, which is addressed in the AMR. The staff's evaluation of the applicant's Bolting Integrity Program is documented in SER Section 3.0.3.1.7. While there is no AMR for loss of preload of stainless steel bolting exposed to air
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| -outdoor in the auxiliary system, the GALL Report has items for other material bolting exposed to air-outdoor managed by the Bolting Integrity Program. The staff finds the applicant's proposa l to manage aging using the Bolting Integrity Program acceptable because the Bolting Integrity Program conducts bolting assembly and maintenance control such as application of appropriate gasket alignment, torque, lubricants, and preload. The program also inspects for leakage and loose or missing nuts which verify that the aging effect, loss of preload, will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation.
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| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed in the GALL Report. The staff finds that the applicant 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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| 3.3.2.3.18 Fuel Storage Building Air Handling System
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| -Aging Management Evaluation
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| -LRA Table 3.3.2
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| -18 The staff reviewed LRA Table 3.3.2
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| -18, which summarizes the results of AMR evaluations for the fuel storage building air handling system component groups.
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| The staff's evaluation for elastomer flexible connectors and flexible hose exposed to air with borated water leakage (external), which are being managed for hardening and loss of strength by the External Surfaces Monitoring Program citing generic Note G, is documented in SER Section 3.3.2.3.3.
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| The staff's evaluation for elastomer flexible connectors exposed to air with borated water leakage (external), which are being managed for loss of material by the External Surfaces Monitoring Program citing generic Note G, is documented in SER Section 3.3.2.3.5.
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| Aging Management Review Results 3-461 On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
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| 3.3.2.3.19 Hot Water Heating System
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| -Aging Management Evaluation
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| -LRA Table 3.3.2
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| -19 The staff reviewed LRA Table 3.3.2
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| -19, which summarizes the results of AMR evaluations for the hot water heating system component groups.
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| The staff's evaluation for stainless steel bolting, exposed to air
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| -indoor and being managed for loss of preload by the Bolting Integrity Program citing generic Note G, is documented in SER Section 3.3.2.3.2.
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| In LRA Tables 3.3.2
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| -19, and 3.3.2
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| -44, the applicant stated that the steel bolting exposed to air
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| -indoor uncontrolled (external) is being managed for loss of preload by the Bolting Integrity Program. The AMR item cites generic Note G.
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| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination.
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| Even though steel bolting exposed to air
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| -indoor uncontrolled is not specifically addressed in the GALL Report, Table IX.E of the GALL Report states that loss of preload can occur independent of environmental conditions because it can be caused by thermal or mechanical effects. Additionally, Table IX.C of the GALL Report states that steel material is susceptible to a variety of aging effects and mechanisms, including loss of material due to general, pitting and crevice corrosion. The staff noted that the applicant addressed loss of material in additional items for each of these components; therefore, the aging effect of concern is loss of preload, which is addressed in the AMR.
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| The staff's evaluation of the applicant's Bolting Integrity Program is documented in SER Section 3.0.3.1.7. While there is no AMR for loss of preload of steel bolting exposed to condensation in the auxiliary system, the GALL Report has items for loss of preload of other material bolting managed by the Bolting Integrity Program. The staff finds the applicant's proposal to manage aging using the Bolting Integrity Program acceptable because the Bolting Integrity Program conducts bolting assembly and maintenance control such as application of appropriate gasket alignment, torque, lubricants, and preload. The program also inspects for leakage and loose or missing nuts, which verify that the aging effect, loss of preload, will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation.
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| The staff's evaluation for glass piping elements exposed to air
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| -with borated water leakage (external), with no AERM and no recommended AMP citing generic Note G, is documented in SER Section 3.3.2.3.3.
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| On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not addressed in the GALL Report. The staff finds that the applicant demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained Aging Management Review Results 3-462 consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
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| 3.3.2.3.20 Instrument Air System
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| -Aging Management Evaluation
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| -LRA Table 3.3.2
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| -20 The staff reviewed LRA Table 3.3.2
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| -20, which summarizes the results of AMR evaluations for the instrument air system component groups.
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| The staff's evaluation for stainless steel bolting, exposed to air
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| -indoor and being managed for loss of preload by the Bolting Integrity Program citing generic Note G, is documented in SER Section 3.3.2.3.2.
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| The staff's evaluation for elastomer flexible connectors and flexible hose exposed to air with borated water leakage (external), which are being managed for hardening and loss of strength by the External Surfaces Monitoring Program citing generic Note G, is documented in SER Section 3.3.2.3.3.
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| The staff's evaluation for polymer (PVC, PVDF, polypropylene, fluoropolymer, polycarbonate, plastic, and polyolefin) piping, piping components, and piping elements, flexible hose, tanks, and instrument elements, exposed to air
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| -indoor uncontrolled (internal or external) and air
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| -indoor controlled external environments with no aging effect and no AMP proposed citing generic Note F, is documented in SER Section 3.3.2.3.4.
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| The staff's evaluation for polymer (PVC, polypropylene, fluoropolymer, polycarbonate, polyolefin, and plastic ) piping, piping components and piping elements, tank and flexible hose exposed to air with borated water external environment, with no aging effect and no AMP proposed citing generic Note F, is documented in SER Section 3.3.2.3.11.
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| The staff's evaluation for aluminum filter housings, instrumentation elements, and valve bodies exposed to dried air, which cite generic Note G, is documented in Section 3.3.2.3.12.
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| In LRA Table 3.3.2
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| -20, the applicant stated that the aluminum heat exchanger components exposed to lubricating oil (internal) are being managed for loss of material by the Lubricating Oil Analysis Program, as augmented by the One
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| -Time Inspection Program. The AMR item cites generic Note F.
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| The staff reviewed the associated items in the LRA and confirmed that no aging effect is applicable for this component, material, and environment combination because of the excellent corrosion resistance that titanium exhibits in air, oxidizing, and aqueous conditions. This is supported by information in the ASM Handbook, Volume 13B Corrosion: Materials, and the Metals Properties Handbook: Titanium Alloys. Titanium and its alloys are fully resistant to general corrosion and pitting in water, natural waters and steam to 600 °F (315 °C). In addition, multiple references (AZo Journal of Materials On
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| -Line, Corrosion Resistance Tables, and Encyclopedia of Chemical Processing and Design) state that titanium is resistant to pitting, general, and crevice corrosion and SCC in turbine exhaust steam environments, in essence due to its formation of very stable, continuous, highly adherent, and protective oxide films on metal surfaces. In addition, the staff also notes that, due to its corrosion resistance capabilities, titanium is widely used in the refinery industry for condenser tubing and the aerospace industry in temperature applications up to 1,112 °F (600 °C). Based on these references and industry applications, the staff finds the applicant's proposal, that there are no other AERMs, acceptable Aging Management Review Results 3-463 based on titanium's resistance to pitting, general, and crevice corrosion and SCC in air and aqueous systems.
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| The staff finds the applicant's proposal to manage aging using the Lubricating Oil Analysis Program, as augmented by the One
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| -Time Inspection Program, acceptable because the Lubricating Oil Analysis Program monitors for contaminants that could cause corrosion and for degradation of the oil, which could be caused by corrosion products. This analysis is supplemented by the One
| |
| -Time Inspection Program, which uses visual examination and other examination techniques to inspect for the loss of material in areas where the most severe aging effects would be expected to occur.
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| In LRA Tables 3.3.2
| |
| -20 and 3.3.2-23, the applicant stated that the aluminum valve body and pump casing components exposed to lubricating oil (internal) are being managed for loss of material by the Lubricating Oil Analysis Program, as augmented by the One
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| -Time Inspection Program. The AMR item cites generic Note G.
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| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material and environment combination. As stated in the ASM Handbook, ASM International, 2005, aluminum is a corrosion
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| -resistant material, and for aluminum valve body and pump casing components internally exposed to oil, the applicant identified the appropriate aging effects (i.e., loss of material). This aging effect is managed by the Lubricating Oil Analysis Program and is augmented by the One
| |
| -Time Inspection Program. The staff's evaluations of the applicant's Lubricating Oil Analysis Program and the One
| |
| -Time Inspection Program are documented in SER Sections 3.0.3.2.16 and 3.0.3.1.8, respectively. The Lubricating Oil Analysis Program performs oil condition monitoring activities to manage the aging effects of loss of material due to galvanic, general, pitting, crevice, and MIC and fouling and heat transfer degradation due to fouling.
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| The One-Time Inspection Program performs a one-time inspection of selected components containing lubricating oil determined to be most susceptible to the potential degradation mechanisms to verify the effectiveness of the Lubricating Oil Analysis Program. The staff finds the applicant's proposal to manage aging using the Lubricating Oil Analysis Program, as augmented by the One
| |
| -Time Inspection Program, acceptable because the Lubricating Oil Analysis Program monitors for contaminants that could cause corrosion and for degradation of the oil, which could be caused by corrosion products. This analysis is supplemented by the One
| |
| -Time Inspection Program, which uses visual examination and other examination techniques to inspect for the loss of material in areas where the most severe aging effects would be expected to occur.
| |
| In LRA Table 3.3.2
| |
| -20, the applicant stated that for polymer (CPVC and fluoropolymer) piping and fittings, and flexible hose exposed to dried air internal environment, there is no aging effect, and no AMP is proposed. The AMR items cite generic Note F. These items also cite plant
| |
| -specific Note 2, which states the following:
| |
| Unlike metals, polymers do not display corrosion rates. Rather than depending on an oxide layer for protection, they depend on chemical resistance to the environment to which they are exposed. The plastic is either completely resistant to the environment or it deteriorates. Therefore, acceptability for the use of polymers within a given environment is a design driven criterion. Once the Aging Management Review Results 3-464 appropriate material is chosen, the system will have no aging effects. This is consistent with plant operating experience.
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| The staff noted that, as identified in Engineering Materials Handbook
| |
| -Engineering Plastics , American Society for Metals International, Copyright 1988, rigid polymers are unaffected by water, concentrated alkalis, non
| |
| -oxidizing acids, oils, ozone, sunlight, or humidity changes. The staff also noted that, unlike metals, thermoplastics do not display corrosion rates, and rather than depend on an oxide layer for protection, they depend on chemical resistance to the environments to which they are exposed and the use of thermoplastics in power plant environments is a design
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| -driven criterion. The staff further noted that thermoplastic material is impervious and, once selected for the environment, will not have any significant age
| |
| -related degradation. The staff reviewed the associated items in the LRA and confirmed that no aging effect is applicable for this component, material, and environment combination because there is no indication in the industry that polymers or thermoplastics exposed to an internal or external indoor air environment have any aging effects requiring management. Additionally, the generally low operating temperatures and historically good chemical resistance data for polymer components, combined with a lack of historically negative operating experience, indicate that polymers are not likely to experience any degradation from the non
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| -aggressive dried air environment.
| |
| In LRA Tables 3.3.2
| |
| -20 and 3.3.2
| |
| -23, the applicant stated that the aluminum components exposed to lubricating oil are being managed for loss of material by the Lubricating Oil Analysis and One-Time Inspection Programs. The AMR item associated with Table 3.3.2
| |
| -20 cites generic Note F, and AMR items associated with Tables 3.3.2
| |
| -23, 3.4.2-6, and 3.4.2
| |
| -7 cite generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination because loss of material may occur due to pitting and crevice corrosion of the aluminum components exposed to lubricating oil in the heat exchanger, valve body, pump casing, and instrumentatio n elements.
| |
| The staff's evaluations of the applicant's Lubricating Oil Analysis and One
| |
| -Time Inspection Programs are documented in SER Section 3.0.3.2.16 and 3.0.3.1.8, respectively. The staff finds the applicant's proposal to manage aging using the Lubricating Oil Analysis and One
| |
| -Time Inspection Programs acceptable because the Lubricating Oil Analysis Program was determined to be consistent with the GALL Report. Additionally, the applicant stated that the One
| |
| -Time Inspection Program will be used to examine aluminum components and elements to verify the effectiveness of the Lubricating Oil Analysis Program.
| |
| In LRA Table 3.3.2
| |
| -20, the applicant stated that elastomer flexible hoses exposed to condensation or dried air (internal) are being managed for hardening and loss of strength with the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The AMR item cites generic Note G.
| |
| The staff reviewed the associated items in the LRA and confirmed that the applicant identified the correct aging effects for this component, material, and environment combination. The GALL Report, Table IX.C, states that elastomers are susceptible to hardening and loss of strength at temperatures over about 95 °F (35 °C) and when exposed to additional aging factors such as ozone, oxidation, and radiation. The staff noted that the environment of interest, condensation Aging Management Review Results 3-465 (internal), has the potential of being in the temperature range for elastomer susceptibility to aging; therefore, the aging effect of concern is hardening and loss of strength, which is addressed in the AMR.
| |
| The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff finds the applicant's proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneou}}
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