ML103010100: Difference between revisions

From kanterella
Jump to navigation Jump to search
(Created page by program invented by StriderTol)
 
(StriderTol Bot change)
 
(4 intermediate revisions by the same user not shown)
Line 3: Line 3:
| issue date = 11/04/2010
| issue date = 11/04/2010
| title = Safety Evaluation Report Related to the License Renewal of Salem Nuclear Generating Station, Units 1 and 2
| title = Safety Evaluation Report Related to the License Renewal of Salem Nuclear Generating Station, Units 1 and 2
| author name = Holian B E
| author name = Holian B
| author affiliation = NRC/NRR/DLR
| author affiliation = NRC/NRR/DLR
| addressee name = Joyce T
| addressee name = Joyce T
Line 19: Line 19:


=Text=
=Text=
{{#Wiki_filter:UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 Mr. Thomas Joyce President and Chief Nuclear Officer PSEG Nuclear LLC P.O. Box 236 Hancocks Bridge , NJ 08038 November 4, 2010
{{#Wiki_filter:}}
 
==SUBJECT:==
SAFETY EVALUATION REPORT RELATED TO THE LICENSE RENEWAL OF SALEM NUCLEAR GENERATING STATION , UNITS 1 AND 2 (TAC NOS. ME1834 AND ME1836)
 
==Dear Mr. Joyce:==
By letter dated August 18, 2009 , Public Service Ente r prise Group Nuclear, LLC, submitted, for the U.S. Nuclear Regulatory Commission (NRC) review , an appl icati on to renew the Salem Nuclear Generating Station (Salem), Units 1 and 2 , operating licenses for an additional 20 years. The license renewal applicat ion (LRA) was submitted pursuant to Title 10 of the Code of Federal Regulations Part 54, "R equirements for Renewal of Operating Licenses for Nuclear Power Plants." The staff determined that the LRA was complete and acceptab le for docketing on October 15, 2009. The staff has reviewed the Salem LRA and has developed the enclosed "Safety Evaluation Report with Open Items Related to the License Renewal of the Salem Nuclear Generating Station, Units 1 and 2," hereafter referred to as the Safety Evaluation Report (SER). This SER refle cts the status of the staff's review of the LRA , requests for additiona l information (RAl s), site audits and insp ections , and th e applicant's responses to the staff's RAls. I ssuance of the enclosed SER is an i mportant milestone for both the applicant and the staff. The staff has i dentified four open it ems in its review which must be resolved before a final determination on the application.
SER Section 1.5 includes a description of the open items with a summary of the i nformation required to resolve the issue. In order to resolve these items , the staff has requested additional information, as identified in the SER. In accordance with the schedule for completing the review of the Salem LRA, the applicant is r equested to review the enclosed SER, verify its accuracy , and provide comments to the staff within 45 days from the date of this letter. The staff plans to review the current content and format of the SER for further improvements while incorporating t h e applicant's comments.
Upcoming milestones for this project include an Advisory Comm i ttee on Reactor Safeguards Subcommittee meeting scheduled for December 1, 2010 , and a final SER which, pending successful r eso lution of the open i tems , is currently scheduled to be issued on or about March 15, 20 11.
T. Joyce I f you have any questions regarding this matter, please contact the License Renewa l Project Manager , Ms. Bennett Brady, 301-415-2981 or bye-mail at Ben n ett.Brady@nrc
.gov. Docke t Nos. 50-272 and 50-311 Enc l os ur e: As stated cc w/enc l: Di s tri but i o n via Listserv Sincerely , Bria n E. Ho li an, D i recto r Div i sion of License Renewa l Office of Nuclear Reactor Regu l at i on U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation November 2010 Safety Evaluation Report With Open Items Related to the License Renewal of Salem Nuclear Generating Station Docket Numbers 50-272 and 50
-311 PSEG Nuclear, LLC
 
THIS PAGE IS INTENTIONALLY LEFT BLANK iii  ABSTRACT This safety evaluation report (SER) documents the technical review of the Salem Nuclear Generating Station, Units 1 and 2, (Salem) license renewal application (LRA) by the U.S. Nuclear Regulatory Commission (NRC) staff (the staff). By letter dated August 18, 2009, PSEG Nuclear, LLC (PSEG or the applicant) submitted the LRA in accordance with Title 10, Part 54, of the Code of Federal Regulations, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants."  PSEG requests renewal of the operating licenses (Facility Operating License Numbers DPR-70 and DPR 75) for a period of 20 years beyond the current expiration at midnight August 13, 2016, for Unit 1, and at midnight on April 18, 2020, for Unit 2. Salem is located approximately 40 miles from Philadelphia, PA, and 8 miles from Salem, NJ. The NRC issued the construction permit s for Unit 1 and Unit 2 on August 25, 1968. The NRC issued the operating license for Unit 1 on December 1, 1976, and for Unit 2 on May 20, 1981. Both units are pressurized water reactors that were designed and supplied by Westinghouse. License Amendment Nos.
243 (Salem Unit 1) and 224 (Salem Unit 2), dated May 25, 2001, which authorized a 1.4 percent increase in the licensed rated power level of each Unit to 3,459 megawatt thermal (MWt).
This SER presents the status of the staff's review of information submitted through October 15 , 2010, the cutoff date for consideration in the SER. The staff identified four open items that must be resolved before any final determination can be made on the LRA. SER Section 1.5 summarizes the open items. The staff will present its final conclusion on the LRA review in an update to this SE R
THIS PAGE IS INTENTIONALLY LEFT BLANK v  TABLE OF CONTENTS ABSTRACT ................................................................................................
..............................
iii TABLE OF CONTENTS
................................................................................................
............
v LIST OF TABLES
................................................................................................
...................
xiv ABBREVIATIONS
................................................................................................
..................
xvi SECTION 1  INTRODUCTION AND GENERAL DISCUSSION
............................................
1-1 1.1  Introduction
................................................................................................
..................
1-1 1.2  License Renewal Background
................................................................
.....................
1-2 1.2.1  Safety Review
................................................................................................
....... 1-3 1.2.2  Environmental Review
..........................................................................................
1-4 1.3  Principal Review Matters
.............................................................................................
1-5 1.4  Interim Staff Guidance
................................................................................................
. 1-6 1.5  Summary of the Open Items
........................................................................................
1-7 1.6  Summary of Confirmatory Items
................................................................
..................
1-9 1.7  Summary of Proposed License Conditions
................................................................
.. 1-9 SECTION 2  STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW
................................................................................................
..... 2-1 2.1  Scoping and Screening Methodology
................................................................
..........
2-1 2.1.1  Introduction
................................................................................................
...........
2-1 2.1.2  Summary of Technical Information in the Application
............................................
2-1 2.1.3  Scoping and Screening Program Review
..............................................................
2-2 2.1.3.1  Implementing Procedures and Documentation Sources Used for Scoping and Screening
................................................................
.....................
2-3 2.1.3.2  Quality Controls Applied to LRA Development
................................
................
2-6 2.1.3.3  Training ................................................................................................
..........
2-7 2.1.3.4  Scoping and Screening Program Review Conclusion
................................
..... 2-7 2.1.4  Plant Systems, Structures, and Components Scoping Methodology
.....................
2-8 2.1.4.1  Application of the Scoping Criteria in 10 CFR 54.4(a)(1)
................................
. 2-8 2.1.4.2  Application of the Scoping Criteria in 10 CFR 54.4(a)(2)
...............................
2-14 2.1.4.3  Application of the Scoping Criteria in 10 CFR 54.4(a)(3)
...............................
2-18 2.1.4.4  Plant-Level Scoping of Systems and Structures ...........................................
2-22 2.1.4.5  Mechanical Component Scoping
.................................................................. 2-24 2.1.4.6  Structural Component Scoping
..................................................................... 2-25 2.1.4.7  Electrical Component Scoping
...................................................................... 2-27 2.1.4.8  Scoping Methodology Conclusion
................................................................
. 2-28 2.1.5  Screening Methodology
......................................................................................
2-28 Table of Content vi 2.1.5.1  General Screening Methodology
................................
................................
... 2-28 2.1.5.2  Mechanical Component Screening
...............................................................
2-30 2.1.5.3  Structural Component Screening
.................................................................. 2-31 2.1.5.4  Electrical Component Screening
................................
................................
... 2-32 2.1.5.5  Screening Methodology Conclusion
..............................................................
2-34 2.1.6  Summary of Evaluation Findings
................................................................
......... 2-34 2.2  Plant-Level Scoping Results
......................................................................................
2-34 2.2.1  Introduction
................................................................................................
......... 2-34 2.2.2  Summary of Technical Information in the Application
................................
..........
2-34 2.2.3  Staff Evaluation
................................................................................................
... 2-35 2.2.4  Conclusion
................................................................................................
..........
2-35 2.3  Scoping and Screening Results:
Mechanical Systems
................................
..............
2-35 2.3.1  Reactor Vessel, Internals, and Reactor Coolant System
................................
..... 2-36 2.3.1.1  Reactor Coolant System
................................................................
...............
2-37 2.3.1.2  Reactor Vessel
................................
.............................................................
2-37 2.3.1.3  Reactor Vessel Internals
................................................................
...............
2-38 2.3.1.4  Steam Generators
........................................................................................
2-39 2.3.2  Engineered Safety Features
................................................................................
2-39 2.3.2.1  Containment Spray System
................................................................
..........
2-39 2.3.2.2  Residual Heat Removal System
................................
................................
... 2-40 2.3.2.3  Safety Injection System
................................................................................
2-41 2.3.3  Auxiliary Systems
................................................................................................
2-41 2.3.3.1  Auxiliary Building Ventilation System
............................................................
2-42 2.3.3.2  Chemical and Volume Control System
..........................................................
2-43 2.3.3.3  Chilled Water System
...................................................................................
2-43 2.3.3.4  Circulating Water System
.............................................................................
2-46 2.3.3.5  Component Cooling System
......................................................................... 2-46 2.3.3.6  Compressed Air System
................................................................
...............
2-48 2.3.3.7  Containment Ventilation System
................................................................... 2-48 2.3.3.8  Control Area Ventilation System
................................................................... 2-49 2.3.3.9  Cranes and Hoists
................................................................
........................
2-50 2.3.3.10  Demineralized Water System
..................................................................... 2-50 2.3.3.11  Emergency Diesel Generator and Auxiliaries System
................................
. 2-51 2.3.3.12  Fire Protection System
................................................................
...............
2-51 2.3.3.13  Fresh Water System
...................................................................................
2-58 2.3.3.14  Fuel Handling and Fuel Storage System
................................
.....................
2-59 2.3.3.15  Fuel Handling Ventilation System
................................
...............................
2-59 2.3.3.16  Fuel Oil System
..........................................................................................
2-60 2.3.3.17  Heating Water and Heating Steam System
................................
.................
2-61 2.3.3.18  Non-radioactive Drain System
.................................................................... 2-61 2.3.3.19  Radiation Monitoring System
................................................................
...... 2-62 2.3.3.20  Radioactive Drain System
...........................................................................
2-62 2.3.3.21  Radwaste System
.......................................................................................
2-64 2.3.3.22  Sampling System
................................................................
........................
2-65 Table of Content vii 2.3.3.23  Service Water System
................................................................
................
2-66 2.3.3.24  Service Water Ventilation System
................................
...............................
2-68 2.3.3.25  Spent Fuel Cooling System
................................................................
........ 2-69 2.3.3.26  Switchgear and Penetration Area Ventilation System
................................
. 2-70 2.3.4  Steam and Power Conversion Systems
..............................................................
2-70 2.3.4.1  Auxiliary Feedwater System
................................................................
......... 2-71 2.3.4.2  Main Condensate and Feedwater System
....................................................
2-71 2.3.4.3  Main Condenser and Air Removal System
...................................................
2-72 2.3.4.4  Main Steam System
......................................................................................
2-72 2.3.4.5  Main Turbine and Auxiliaries System
............................................................
2-73 2.4  Scoping and Screening Results:  Structures
..............................................................
2-74 2.4.1  Auxiliary Building
................................................................................................
. 2-75 2.4.1.1  Summary of Technical Information in the Application
................................
.... 2-75 2.4.1.2  Conclusion
................................................................................................
.... 2-75 2.4.2  Component Supports Commodity Group
.............................................................
2-76 2.4.2.1  Summary of Technical Information in the Application
................................
.... 2-76 2.4.2.2  Conclusion
................................................................................................
.... 2-76 2.4.3  Containment Structure
................................................................
........................
2-77 2.4.3.1  Summary of Technical Information in the Application
................................
.... 2-77 2.4.3.2  Conclusion
................................................................................................
.... 2-77 2.4.4  Fire Pump House
................................................................................................
2-77 2.4.4.1  Summary of Technical Information in the Application
................................
.... 2-77 2.4.4.2  Staff Evaluation
................................................................
............................
2-78 2.4.4.3  Conclusion
................................................................................................
.... 2-78 2.4.5  Fuel Handling Building
................................................................
........................
2-79 2.4.5.1  Summary of Technical Information in the Application
................................
.... 2-79 2.4.5.2  Conclusion
................................
................................................................
.... 2-79 2.4.6  Office Buildings
................................................................
................................
... 2-79 2.4.6.1  Summary of Technical Information in the Application
................................
.... 2-79 2.4.6.2  Conclusion
................................
................................................................
.... 2-80 2.4.7  Penetration Areas
...............................................................................................
2-80 2.4.7.1  Summary of Technical Information in the Application
................................
.... 2-80 2.4.7.2  Conclusion
................................
................................................................
.... 2-80 2.4.8  Pipe Tunnel
................................................................................................
......... 2-81 2.4.8.1  Summary of Technical Information in the Application
................................
.... 2-81 2.4.8.2  Conclusion
................................
................................................................
.... 2-81 2.4.9  Piping and Component Insulation Commodity Group
..........................................
2-81 2.4.9.1  Summary of Technical Information in the Application
................................
.... 2-81 2.4.9.2  Conclusion
................................
................................................................
.... 2-81 2.4.10  SBO Compressor Building
................................................................
................
2-82 2.4.10.1  Summary of Technical Information in the Application
................................
.. 2-82 2.4.10.2  Conclusion
................................................................................................
.. 2-82 2.4.11  Service Building
................................................................................................
2-82 2.4.11.1  Summary of Technical Information in the Application
................................
.. 2-82 Table of Content viii 2.4.11.2  Conclusion
................................................................................................
.. 2-83 2.4.12  Service Water Accumulator Enclosures
............................................................
2-83 2.4.12.1  Summary of Technical Information in the Application
................................
.. 2-83 2.4.12.2  Staff Evaluation
..........................................................................................
2-83 2.4.12.3  Conclusion
................................................................................................
.. 2-84 2.4.13  Service Water Intake
.........................................................................................
2-84 2.4.13.1  Summary of Technical Information in the Application
................................
.. 2-84 2.4.13.2  Conclusion
................................................................................................
.. 2-85 2.4.14  Shoreline Protection and Dike
................................................................
...........
2-85 2.4.14.1  Summary of Technical Information in the Application
................................
.. 2-85 2.4.14.2  Staff Evaluation
..........................................................................................
2-85 2.4.14.3  Conclusion
................................................................................................
.. 2-86 2.4.15  Switchyard
................................................................................................
........ 2-86 2.4.15.1  Summary of Technical Information in the Application
................................
.. 2-86 2.4.15.2  Conclusion ................................................................................................
.. 2-86 2.4.16  Turbine Building
................................................................................................
2-87 2.4.16.1  Summary of Technical Information in the Application
................................
.. 2-87 2.4.16.2  Conclusion
................................................................................................
.. 2-87 2.4.17  Yard Structures
................................................................................................
. 2-87 2.4.17.1  Summary of Technical Information in the Application
................................
.. 2-87 2.4.17.2  Conclusion
................................................................................................
.. 2-88 2.5  Scoping and Screening Results:  Electrical and Instrumentation and Controls (I&C) Systems
................................................................................................
..... 2-88 2.5.1  Electrical/I&C Component Commodity Groups
....................................................
2-89 2.5.1.1  Summary of Technical Information in the Application
................................
.... 2-89 2.5.1.2  Staff Evaluation ................................................................
............................
2-89 2.5.1.3  Conclusion
................................................................................................
.... 2-90 2.6  Conclusion for Scoping and Screening ...................................................................... 2-91 SECTION 3  AGING MANAGEMENT REVIEW RESULTS
................................
..................
3-1 3.0  Applicant's Use of the Generic Aging Lessons Learned Report
................................
... 3-1 3.0.1  Format of the License Renewal Application
................................
..........................
3-2 3.0.1.1  Overview of Table 1s
......................................................................................
3-2 3.0.1.2  Overview of Table 2s
......................................................................................
3-3 3.0.2  Staff's Review Process
.........................................................................................
3-4 3.0.2.1  Review of AMPs
.............................................................................................
3-4 3.0.2.2  Review of AMR Results
..................................................................................
3-5 3.0.2.3  UFSAR Supplement .......................................................................................
3-6 3.0.2.4  Documentation and Documents Reviewed
.....................................................
3-6 3.0.3  Aging Management Programs
...............................................................................
3-6 3.0.3.1  AMPs That Are Consistent with the GALL Report
......................................... 3-10 3.0.3.2  AMPS That Are Consistent with the GALL Report with Exceptions or Enhancements
...........................................................................................
3-76 Table of Content ix 3.0.3.3  AMPs That Are Not Consistent with or Not Addressed in the GALL Report
................................................................................................
3-165 3.0.4  Quality Assurance Program Attributes Integral to Aging Management Programs ................................................................................................
......... 3-197 3.0.4.1  Summary of Technical Information in Application
....................................... 3-197 3.0.4.2  Staff Evaluation
................................................................
..........................
3-197 3.0.4.3  Conclusion
................................................................................................
.. 3-198 3.1  Aging Management of Reactor Vessel, Internals, and Reactor Coolant System
...... 3-198 3.1.1  Summary of Technical Information in the Application
........................................ 3-198 3.1.2  Staff Evaluation
................................................................................................
. 3-199 3.1.2.1  AMR Results That Are Consistent with the GALL Report
............................
3-217 3.1.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended
............................................................
3-233 3.1.2.3  AMR Results That Are Not Consistent With or Not Addressed in the GALL Report
................................................................................................
3-257 3.1.3  Conclusion
................................................................................................
........ 3-263 3.2  Aging Management of Engineered Safety Features
.................................................
3-263 3.2.1  Summary of Technical Information in the Application
........................................ 3-263 3.2.2  Staff Evaluation
................................................................................................
. 3-264 3.2.2.1  AMR Results That Are Consistent with the GALL Report
............................
3-273 3.2.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation Is Recommended
............................................................
3-281 3.2.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report
................................................................................................
3-290 3.2.3  Conclusion
................................................................................................
........ 3-291 3.3  Aging Management of Auxiliary Systems
................................................................
. 3-291 3.3.1  Summary of Technical Information in the Application
........................................ 3-292 3.3.2  Staff Evaluation
................................................................................................
. 3-292 3.3.2.1  AMR Results That Are Consistent with the GALL Report
............................
3-308 3.3.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended
............................................................
3-333 3.3.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report
................................................................................................
3-362 3.3.3  Conclusion
................................................................................................
........ 3-384 3.4  Aging Management of Steam and Power Conversion Systems
...............................
3-385 3.4.1  Summary of Technical Information in the Application
........................................ 3-385 3.4.2  Staff Evaluation
................................................................
................................
. 3-385 3.4.2.1  AMR Results That Are Consistent with the GALL Report
............................
3-392 3.4.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended
............................................................
3-398 3.4.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report
................................................................................................
3-409 3.4.3  Conclusion
................................................................................................
........ 3-411 3.5  Aging Management of Containments, Structures, and Component Supports
...........
3-412 Table of Content x 3.5.1  Summary of Technical Information in the Application
................................
........ 3-412 3.5.2  Staff Evaluation
................................................................................................
. 3-412 3.5.2.1  AMR Results That Are Consistent with the GALL Report
............................
3-426 3.5.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation Is Recommended
............................................................
3-446 3.5.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report
................................................................................................
3-474 3.5.3  Conclusion
................................................................................................
........ 3-49 8 3.6  Aging Management of Electrical and Instrumentation and Controls
.........................
3-498 3.6.1  Summary of Technical Information in the Application ................................
........ 3-498 3.6.2  Staff Evaluation
................................................................................................
. 3-499 3.6.2.1  AMR Results That Are Consistent with the GALL Report
............................
3-502 3.6.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended
............................................................
3-504 3.6.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report
................................................................................................
3-508 3.6.3  Conclusion
................................................................................................
........ 3-510 3.7  Conclusion for Aging Management Review Results
.................................................
3-510 SECTION 4  TIME-LIMITED AGING ANALYSES
................................................................
. 4-1 4.1  Identification of Time
-Limited Aging Analyses
..............................................................
4-1 4.1.1  Summary of Technical Information in the Application
................................
............
4-1 4.1.2  Staff Evaluation
................................................................................................
..... 4-2 4.1.3  Conclusion
................................................................................................
............
4-4 4.2  Reactor Vessel Neutron Embrittlement
........................................................................ 4-4 4.2.1  Neutron Fluence Analysis
................................................................
.....................
4-5 4.2.1.1  Summary of Technical Information in the Application
................................
...... 4-5 4.2.1.2  Staff Evaluation
................................................................
..............................
4-5 4.2.1.3  UFSAR Supplement
.......................................................................................
4-6 4.2.1.4  Conclusion
................................
................................................................
...... 4-6 4.2.2  Upper-Shelf Energy Analyses
...............................................................................
4-7 4.2.2.1  Summary of Technical Information in the Application
................................
...... 4-7 4.2.2.2  Staff Evaluation
..............................................................................................
4-7 4.2.2.3  UFSAR Supplement
.......................................................................................
4-9 4.2.2.4  Conclusion
................................
................................................................
...... 4-9 4.2.3  Pressurized Thermal Shock Analyses
................................................................... 4-9 4.2.3.1  Summary of Technical Information in the Application
................................
...... 4-9 4.2.3.2  Staff Evaluation
............................................................................................
4-10 4.2.3.3  UFSAR Supplement
.....................................................................................
4-11 4.2.3.4  Conclusion
................................
................................................................
.... 4-11 4.2.4  Reactor Vessel Pressure
-Temperature Limits, Including Low Temperature Overpressurization Protection Limits
.................................................................. 4-12 4.2.4.1  Summary of Technical Information in the Application
................................
.... 4-12 4.2.4.2  Staff Evaluation
............................................................................................
4-12 Table of Content xi 4.2.4.3  UFSAR Supplement
.....................................................................................
4-13 4.2.4.4  Conclusion
................................................................................................
.... 4-13 4.3  Metal Fatigue of Piping and Components
.................................................................. 4-13 4.3.1  Nuclear Steam Supply System Pressure Vessel and Component Fatigue Analyses
...............................................................................................
4-14 4.3.1.1  Summary of Technical Information in the Application
................................
.... 4-14 4.3.1.2  Staff Evaluation
................................................................
............................
4-14 4.3.1.3  UFSAR Supplement
.....................................................................................
4-16 4.3.1.4  Conclusion
................................................................................................
.... 4-16 4.3.2  Pressurizer Safety Valve and Pilot
-Operated Relief Valve Fatigue Analyses
....... 4-17 4.3.2.1  Pressurizer Safety Valve................................................................
...............
4-17 4.3.2.2  Pressurizer Pilot
-Operated Relief Valve Fatigue Analyses ............................
4-18 4.3.3  American Standards Association/United States of America Standards B31.1 Piping Fatigue Analyses
................................................................
..........
4-20 4.3.3.1  Summary of Technical Information in the Application
................................
.... 4-20 4.3.3.2  Staff Evaluation
................................................................
............................
4-20 4.3.3.3  UFSAR Supplement
.....................................................................................
4-20 4.3.3.4  Conclusion
................................................................................................
.... 4-20 4.3.4  Supplementary ASME Code Section III, Class 1 Piping and Component Fatigue Analyses
...............................................................................................
4-21 4.3.4.1  NRC Bulletin 88
-08, Thermal Stresses in Piping Connected to Reactor Coolant Systems
................................................................
............................
4-21 4.3.4.2  NRC Bulletin 88
-11, Pressurizer Surge Line Thermal Stratification
...............
4-22 4.3.4.3  Salem Unit 1 Steam Generator Feedwater Nozzle Transition Piece
.............
4-24 4.3.4.4  Salem Unit 1 Steam Generator Primary Manway Studs
................................
4-25 4.3.5  Reactor Vessel Internals Fatigue Analyses
................................
.........................
4-27 4.3.5.1  Summary of Technical Information in the Application
................................
.... 4-27 4.3.5.2  Staff Evaluation
............................................................................................
4-27 4.3.5.3  UFSAR Supplement
.....................................................................................
4-28 4.3.5.4  Conclusion
................................
................................................................
.... 4-28 4.3.6  Spent Fuel Pool Bottom Plates Fatigue Analyses
................................
...............
4-28 4.3.6.1  Summary of Technical Information in the Application
................................
.... 4-28 4.3.6.2  Staff Evaluation
............................................................................................
4-28 4.3.6.3  UFSAR Supplement
.....................................................................................
4-29 4.3.6.4  Conclusion
................................
................................................................
.... 4-29 4.3.7  Environmentally
-Assisted Fatigue Analyses
................................
........................
4-29 4.3.7.1  Summary of Technical Information in the Application
................................
.... 4-29 4.3.7.2  Staff Evaluation
............................................................................................
4-30 4.3.7.3  UFSAR Supplement
.....................................................................................
4-33 4.3.7.4  Conclusion
................................
................................................................
.... 4-33 4.4  Other Plant
-Specific Analyses
....................................................................................
4-33 4.4.1  Reactor Vessel Underclad Cracking Analyse s ....................................................
4-33 4.4.1.1  Summary of Technical Information in the Application
................................
.... 4-33 4.4.1.2  Staff Evaluation
............................................................................................
4-34 Table of Content xii 4.4.1.3  UFSAR Supplement
.....................................................................................
4-34 4.4.1.4  Conclusion
................................................................................................
.... 4-35 4.4.2  Reactor Coolant Pump Flywheel Fatigue Crack Growth Analyses
......................
4-35 4.4.2.1  Summary of Technical Information in the Application
................................
.... 4-35 4.4.2.2  Staff Evaluation
................................................................
............................
4-35 4.4.2.3  UFSAR Supplement
.....................................................................................
4-37 4.4.2.4  Conclusion
................................................................................................
.... 4-37 4.4.3  Leak-Before-Break Analyses
................................................................
...............
4-37 4.4.3.1  Summary of Technical Information in the Application
................................
.... 4-37 4.4.3.2  Staff Evaluation
................................................................
............................
4-38 4.4.3.3  UFSAR Supplement
.....................................................................................
4-44 4.4.3.4  Conclusion
................................................................................................
.... 4-44 4.4.4  Applicability of ASME Code Case N
-481 to the Salem Units 1 and 2 Reactor Coolant Pump Casings
................................................................
......... 4-45 4.4.4.1  Summary of Technical Information in the Application
................................
.... 4-45 4.4.4.2  Staff Evaluation
................................................................
............................
4-45 4.4.4.3  UFSAR Supplement
.....................................................................................
4-47 4.4.4.4  Conclusion
................................................................................................
.... 4-47 4.4.5  Salem Unit 1 Volume Control Tank Flaw Growth Analysis
................................
.. 4-47 4.4.5.1  Summary of Technical Information in the Application
................................
.... 4-47 4.4.5.2  Staff Evaluation
................................................................
............................
4-48 4.4.5.3  UFSAR Supplement
.....................................................................................
4-50 4.4.5.4  Conclusion
................................................................................................
.... 4-50 4.5  Fuel Transfer Tube Bellows Design Cycles
................................................................
4-51 4.5.1  Summary of Technical Information in the Application
................................
..........
4-51 4.5.2  Staff Evaluation
................................................................................................
... 4-51 4.5.3  UFSAR Supplement
................................................................
............................
4-52 4.5.4  Conclusion
................................................................................................
..........
4-52 4.6  Crane Load Cycle Limits
................................................................
............................
4-52 4.6.1  Polar Gantry Crane
................................
.............................................................
4-52 4.6.1.1  Summary of Technical Information in the Application
................................
.... 4-52 4.6.1.2  Staff Evaluation
................................................................
............................
4-52 4.6.1.3  UFSAR Supplement
.....................................................................................
4-54 4.6.1.4  Conclusion
................................................................................................
.... 4-54 4.6.2  Fuel Handling Crane
...........................................................................................
4-54 4.6.2.1  Summary of Technical Information in the Application
................................
.... 4-54 4.6.2.2  Staff Evaluation
................................................................
............................
4-54 4.6.2.3  UFSAR Supplement
.....................................................................................
4-55 4.6.2.4  Conclusion
................................................................................................
.... 4-55 4.6.3  Cask Handling Crane
..........................................................................................
4-55 4.6.3.1  Summary of Technical Information in the Application
................................
.... 4-55 4.6.3.2  Staff Evaluation
................................................................
............................
4-55 4.6.3.3  Conclusion
................................................................................................
.... 4-56 4.7  Environmental Qualification of Electrical Equipment
................................
..................
4-56 Table of Content xiii 4.7.1  Summary of Technical Information in the Application
..........................................
4-56 4.7.2  Staff Evaluation
................................................................................................
... 4-56 4.7.3  UFSAR Supplement
................................................................
............................
4-57 4.7.4  Conclusion
................................................................................................
..........
4-57 4.8  Conclusion 58 SECTION 5  REVIEW BY THE ADVISORY COMMITTEE ON REACTOR  SAFEGUARDS
................................................................................................
.....................
5-1 SECTION 6  CONCLUSION
................................................................................................
. 6-1 Appendix A SALEM NUCLEAR GENERATING STATION LICENSE RENEWAL COMMITMENTS
................................................................................................
...................
A-1 Appendix B CHRONOLOGY
................................
...............................................................
B-1 Appendix C PRINCIPAL CONTRIBUTORS
................................................................
......... C-1 Appendix D References
................................................................................................
...... D-1 xiv  LIST OF TABLES Table 1.4-1  Current and Proposed Interim Staff Guidance
.....................................................
1-7 Table 3.0.3-1  Salem Units 1 and 2 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
.................................................
3-200 Table 3.2-1  Staff Evaluation for Engineered Safety Features Systems Components in the GALL Report
................................................................................................
.............
3-264 Table  3.3-1  Staff Evaluation for Auxiliary Systems Components in the GALL Report
........ 3-293 Table 3.4-1  Staff Evaluation for Steam and Power Conversion System Components in the GALL Report
................................................................................................
.............
3-386 Table 3.5-1 Staff Evaluation for Structures and Component Supports Components in the GALL Report
................................................................................................
.................
3-413 Table 3.6-1  Staff Evaluation for Electrical and Instrumentation and Controls in the GALL Report
.......................................................................................................................
3-49 9 THIS PAGE IS INTENTIONALLY LEFT BLANK xvi  ABBREVIATIONS AC  alternating current ACAR  aluminum-alloyed reinforced ACI  American Concrete Institute ACRS  Advisory Committee on Reactor Safeguards ACSR  aluminum conductor steel reinforced ADAMS  Agencywide Document Access and Management System ADV  atmospheric dump valve AERM  aging effect requiring management AFW  auxiliary feedwater AISC  American Institute of Steel Construction AMP  aging management program AMR  aging management review ANSI  American National Standards Institute ART  adjusted reference temperature ASME  American Society of Mechanical Engineers ASTM  American Society for Testing and Materials ATWS  anticipated transient without scram B&PV  Boiler and Pressure Vessel B&W  Babcock & Wilcox BMI  bottom mounted instrumentation BOP  balance of plant BTP  branch technical position BWR  boiling-water reactor BWRVIP  Boiling Water Reactor Vessel and Internals Project CASS  cast austenitic stainless steel
 
Abbreviations xvii  CB&I  Chicago Bridge and Iron CBF  cycle-based fatigue CCW  component cooling water CCCW  closed cycle cooling water CEA  control element assembly CETNA  core exit thermocouple nozzle assembly CFR  Code of Federal Regulations CLB  current licensing basis CMAA  Crane Manufacturers Association of America CO2  carbon dioxide CRD  control rod drive CRDM  control rod drive mechanism CRGT  control rod guide tube CS  containment spray CST  condensate storage tank Cu  copper CUF  cumulative usage factor CVCS  chemical and volume control CVUSE  Charpy upper
-shelf energy CW  circulating water DBA  design-basis accident DBD  design-basis document DBE  design-basis event DC  direct current EAF  environmentally
-assisted fatigue ECCS  emergency core cooling system
 
Abbreviations xviii ECP  electrochemical corrosion potential EDG  emergency diesel generator EFPY  effective full
-power year EHC  electro-hydraulic control EMA  equivalent margin analysis EN  shelter or protection EPRI  Electric Power Research Institute EPU  extended power uprate EQ  environmental qualification ER Environmental Report (Applicant's Environmental Report Operating License Renewal Stage)
ESF  engineered safety features EVT  enhanced visual testing FAC  flow accelerated corrosion Fen  environmental fatigue life correction factor FERC  Federal Energy Regulatory Commission FLB  flood barrier FLT  filtration FMP  Fatigue Monitoring Program FR  Federal Register FRV  feedwater regulating valve FRVS  filtration, recirculation, and ventilation system ft-lb  foot-pound FW  feedwater FWST  fire water storage tank GALL  Generic Aging Lessons Learned Report GDC  general design criteria or general design criterion
 
Abbreviations xix  GEIS  Generic Environmental Impact Statement GL  generic letter GSI  generic safety issue H2  hydrog en HCGS  Hope Creek Generating Station HELB  high-energy line break HEPA  high-efficiency particulate air HPCI  high-pressure coolant injection HPSI  high-pressure safety injection HVAC  heating, ventilation, and air conditioning HWC  hydrogen water chemistry HX  heat exchanger I&C  instrumentation and controls IA  instrument air IASCC  irradiation
-assisted stress
-corrosion cracking ID  inside diameter ID IGA  inside diameter intergranular attack IEEE  Institute of Electrical and Electronics Engineers IGA  intergranular attack IGSCC  intergranular stress
-corrosion cracking ILRT  integrated leak rate testing IN  information notice INPO  Institute of Nuclear Power Operations IPA  integrated plant assessment ISG  interim staff guidance ISI  inservice inspection
 
Abbreviations xx ISP  integrated surveillance program ksi  thousands of pounds per square inch KV or kV  kilovolt LBB  leak before break LCO  Limited Condition Operation LLRT  local leak
-rate test LOCA  loss of coolant accident LPCI  low-pressure coolant injection LPRM  local power range monitor LRA  license renewal application MB  missile barrier MC  metal clad MELB  medium-energy line break MFW  main feedwater mg/L  milligrams per liter MIC  microbiologically
-influenced corrosion MIRVSP  master integrated reactor vessel surveillance program MOV  motor-operated valve mph  miles per hour MS  main steam MSIP  Mechanical Stress Improvement MSIV  main steam isolation valve MWe  megawatts-electric MWt  megawatts-thermal n/cm 2  neutrons per square centimeter
 
Abbreviations xxi  NDE  nondestructive examination NEI  Nuclear Energy Institute NESC  National Electrical Safety Code NFPA  National Fire Protection Association Ni  nickel NMCA  noble metals chemical addition NPS  nominal pipe size NRC  U.S. Nuclear Regulatory Commission NSAC  Nuclear Safety Analysis Center NSSS  nuclear steam supply system NWC  normal water chemistry O 2  oxygen OBE  operating basis earthquake OCCW  open cycle cooling water OD IGA  outside diameter intergranular attack ODSCC  outside-diameter stress
-corrosion cracking OI  open item OTSG  once-through steam generator P&ID  piping and instrumentation diagram PAB  primary auxiliary building PB  pressure boundary PBD  program basis document PDI  Performance Demonstration Initiative pH  potential of hydrogen PMH  probable maximum hurricane PoF  probability of failure
 
Abbreviations xxii PORV  power-operated relief valve ppm  parts per million PSEG  PSEG Nuclear, LLC psi  pounds per square inch PSPM  periodic surveillance and preventive maintenance P-T  pressure-temperature PTS  pressurized thermal shock PUAR  plant unique analysis report PVC  polyvinyl chloride PW  primary water makeup PWR  pressurized water reactor PWSCC  primary water stress
-corrosion cracking QA  quality assurance QAP  quality assurance program RAI  request for additional information RAMA  Radiation Analysis Modeling Application RCCA  rod cluster control assembly RCIC  reactor core isolation cooling RCP  reactor coolant pump RCPB  reactor coolant pressure boundary RCS  reactor coolant system RG  regulatory guide RHR  residual heat removal RI-ISI  risk informed
-inservice inspection RM  radiation monitoring RO  refueling outage
 
Abbreviations xxiii  RPV  reactor pressure vessel RTNDT  reference temperature nil
-ductility transition RTPTS  reference temperature for pressurized thermal shock RTD  resistance temperature detector RV  reactor vessel RVCH  reactor vessel closure head RVI  reactor vessel internal RVID  Reactor Vessel Integrity Database RVLIS  reactor vessel level indication system RW  river water RWCU  reactor water cleanup RWST  refueling water storage tank SA  stress allowable SACS  safety auxiliaries cooling system Salem  Salem Nuclear Generating Station SAP  Systems, Applications, and Products in Data Processing SBF  stress-based fatigue SBO  station blackout SC  structure and component SCC  stress-corrosion cracking SE  safety evaluation SER  safety evaluation report SFP  spent fuel pool SFPC  spent fuel pit/pool cooling SG  steam generator SGBD  steam generator blowdown SHE  standard hydrogen electrode
 
Abbreviations xxiv SI  safety injection SLC  standby liquid contr ol SMP  structures monitoring program SO2  sulfur dioxide SOC  statement of consideration SOV  solenoid-operated valve SPU  stretch power uprate SR  surveillance requirement SRP-LR  Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants SRV  safety relief valve SSC  system, structure, and component SSE  safe-shutdown earthquake SSFS  safety system function sheets SW  service water TAN  total acid number TBN  total base number TIP  transversing in
-core probe TLAA  time-limited aging analysis TOC  total organic carbon TS  technical specification(s)
TSC  technical support center UFSAR  updated final safety analysis report USE  upper-shelf energy UT  ultrasonic testing UV  ultraviolet
 
Abbreviations xxv  VCT  volume control tank VFLD  vessel flange leak detection VHP  vessel head penetration VT  visual testing Yr  year Zn  zinc 1/4 T  one-fourth of the way through the vessel wall measured from the internal surface of the vessel
 
THIS PAGE IS INTENTIONALLY LEFT BLANK 1-1 SECTION 1    INTRODUCTION AND GENERAL DISCUSSION 1.1  Introduction This document is a safety evaluation report (SER) on the license renewal application (LRA) for Salem Nuclear Generating Station, Units 1 and 2 (Salem), as filed by PSEG Nuclear, LLC, (PSEG or the applicant). By letter dated August 18, 2009, PSEG submitted its application to the U.S. Nuclear Regulatory Commission (NRC) for renewal of the Salem operating licenses for an additional 20 years. The NRC staff (the staff) prepared this report to summarize the results of its safety review of the LRA for compliance with Title 10, Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants," of the Code of Federal Regulations (10 CFR Part 54). The NRC project manager for the license renewal review is Bennett M. Brady. Dr. Brady may be contacted by telephone at 301-415-2981 or by electronic mail at Bennett.Brady@nrc.gov. Alternatively, written correspondence may be sent to the following address: Division of License Renewal U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Attention: Bennett M. Brady, Mail Stop 011-F1 In its August 18, 2009, submission letter, the applicant requested renewal of the operating licenses issued under Section 103 (Operating License Nos. DPR
-70 and DPR 75) of the Atomic Energy Act of 1954, as amended, for a period of 20 years beyond the current expiration at midnight April 13, 2016, for Unit 1, and at midnight April 18, 2020, for Unit 2. Salem is located approximately 40 miles from Philadelphia, PA, and 8 miles from Salem, NJ.
The NRC issued the construction permits for Unit 1 and Unit 2 on September 25, 1968. The NRC issued the operating license for Unit 1 on December 1, 1976, and for Unit 2 on May 20, 1981.
Both units are pressurized water reactors (PWRs) that were designed and supplied by Westinghouse. The licensed power output of both unit s is 3,459 megawatt thermal. The updated final safety analysis report (UFSAR) shows details of the plants 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 Salem 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 in audits, meetings, and docketed correspondence. Unless otherwise noted, the staff reviewed and considered information submitted through October 1 5, 2010. The staff may consider information received after that date depending on the progress of the safety review and the volume and complexity of the information. The public may view the LRA and all pertinent information and materials, including the UFSAR, at the NRC Public Document Room, located on the first floor of One White Flint North, 11555 Rockville Pike, Rockville, MD 20852-2738 (301-415-4737 / 800-397-4209), and at the Salem Free Library, 112 West Broadway, Salem, NJ 08079. In addition, the public may find Introduction and General Discussion 1-2 the LRA, as well as materials related to the license renewal review, on the NRC Web site at http://www.nrc.gov.
This SER summarizes the results of the staff's safety review of the LRA and describes the technical details considered in evaluating the safety aspects of the units' proposed operation for an additional 20 years beyond the term of the current operating license. The staff reviewed the LRA in accordance with NRC regulations and the guidance in NUREG
-1800, Revision 1, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants" (SRP-LR), dated September 2005. SER Sections 2 through 4 address the staff's evaluation of license renewal issues considered during the review of the application. SER Section 5 is reserved for the report of the Advisory Committee on Reactor Safeguards (ACRS). The conclusions of this SER are in Section 6. SER Appendix A is a table showing the applicant's commitments for renewal of the operating license. SER Append ix B is a chronology of the principal correspondence between the staff and the applicant regarding the LRA review. SER Appendix C is a list of principal contributors to the SER, and Appendix D is a bibliography of the references in support of the staff's review.
In accordance with 10 CFR Part 51, the staff prepared a draft plant
-specific supplement to NUREG-1437, "Generic Environmental Impact Statement for License Renewal of Nuclear Plants (GEIS)."  Issued separately from this SER, this supplement discusses the environmental considerations for the license renewal of Salem along with those of Hope Creek Generating Station.
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 on the basis of economic and antitrust considerations, rather than on technical limitations; however, some individual plant and equipment designs may have been engineered based on an expected 40
-year service life.
In 1982, the staff anticipated interest in license renewal and held a workshop on nuclear power plant aging. This workshop led the NRC to establish a comprehensive program plan for nuclear plant aging research. From the results of that research, a technical review group concluded that many aging phenomena are readily manageable and pose no technical issues precluding life extension for nuclear power plants. In 1986, the staff published a request for comment on a policy statement that would address major policy, technical, and procedural issues related to license renewal for nuclear power plants.
In 1991, the staff published 10 CFR Part 54, the License Renewal Rule (Volume 56, page 64943, of the Federal Register (56 FR 64943), dated December 13, 1991). The staff participated in an industry-sponsored demonstration program to apply 10 CFR Part 54 to a pilot plant and to gain the experience necessary to develop implementation guidance. To establish a scope of review for license renewal, 10 CFR Part 54 defined age
-related degradation unique to license renewal; however, during the demonstration program, the staff found that adverse aging effects on plant systems and components are managed during the period of initial license and that the scope of the review did not allow sufficient credit for management programs, particularly the
 
Introduction and General Discussion 1-3 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. Published on May 8, 1995, in Volume 60, page 22461, of the Federal Register (60 FR 22461), the 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, 1 0 CFR Part 54 focuses on the management of adverse aging effects rather than on the identification of age
-related degradation unique to license renewal. The staff made these rule changes to ensure that important systems, structures, and components (SSCs) will continue to perform their intended functions during the period of extended operation. In addition, the amended 10 CFR Part 54 clarifies and simplifies the integrated plant assessment process to be consistent with the revised focus on passive, long-lived structures and components (SCs).
Concurrent with these initiatives, the staff pursued a separate rulemaking effort (Volume 61, page 28467, of the Federal Register (61 FR 28467), dated 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 exception of the detrimental aging effects on the function of certain SSCs, as well as a few other safety-related issues, during the period of extended operation.
  (2) The plant-specific licensing basis must be maintained during the renewal term in the same manner and to the same extent as during the original licensing term.
In implementing these two principles, 10 CFR 54.4 defines the scope of license renewal as including SSCs:  (1) that are safety
-related, (2) whose failure could affect safety
-related functions, or (3) that are relied on to demonstrate compliance with NRC 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 are those which perform an intended function without moving parts or without a change in configuration or properties (i.e., are "passive"), and are not subject to replacement based on a qualified life or specified time period (i.e., are "long
-lived"). As required by 10 CFR 54.21(a), an applicant for a renewed license must demonstrate that aging effects will be managed in such a way that the intended function(s) of those SSCs will be maintained, consistent with the current licensing basis (CLB), for the period of extended operation; however, active equipment is considered adequately monitored and maintained by existing programs. In other words, detrimental aging effects that may affect active equipment are readily detectable and can be identified and corrected through routine surveillance, performance monitoring, and maintenance. Surveillance and maintenance programs for active equipment, as well as other Introduction and General Discussion 1-4 maintenance aspects of plant design and licensing basis, are required throughout the period of extended operation.
Pursuant to 10 CFR 54.21(d), each LRA is required to include a UFSAR supplement that must have a summary description of the applicant's programs and activities for managing aging effects and the evaluation of time
-limited aging analyses (TLAAs) for the period of extended operation.
License renewal also requires TLAA identification and updating. During the plant design phase, certain assumptions are made about the length of time the plant can operate. These assumptions are incorporated into design calculations for several plant SSCs. In accordance with 10 CFR 54.21(c)(1), the applicant must show that these calculations will remain valid for the period of extended operation, project the analyses to the end of the period of extended operation, or demonstrate that effects of aging on these SSCs can be adequately managed for the period of extended operation.
In 2001, the staff developed and issued Regulatory Guide (RG) 1.188, "Standard Format and Content for Applications to Renew Nuclear Power Plant Operating Licenses."  This RG endorses Nuclear Energy Institute (NEI) 95-10, Revision 6, "Industry Guideline for Implementing the Requirements of 10 CFR Part 54 - The License Renewal Rule" (NEI 95-10), issued in March 2001 by the NEI. NEI 95-10 details an acceptable method of implementing the Rule. The staff also used the SRP
-LR to review this application.
In its LRA, the applicant stated that it used the process defined in NUREG
-1801, "Generic Aging Lessons Learned (GALL) Report," issued in July 2001 and subsequently revised in September 2005. The GALL Report provides a summary of staff
-approved aging management programs (AMPs) for the aging of many SCs subject to an AMR. An applicant's willingness to commit to implementing these staff
-approved AMPs could potentially reduce the time, effort, and resources in reviewing an applicant's LRA, and thereby, improve 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 SCs used throughout the industry. The report is also a reference for both applicants and staff reviewers to quickly identify AMPs and activities that can provide adequate aging management during the period of extended operation.
1.2.2  Environmental Review In December 1996, the staff revised the environmental protection regulations to facilitate the environmental review for license renewal. The staff prepared the GEIS to document its evaluation of the possible environmental impacts associated with renewing licenses of nuclear power plants. For certain types of environmental impacts, the GEIS establishes generic findings applicable to all nuclear power plants. These generic findings are codified in Appendix B to Subpart A of 10 CFR Part 51. Pursuant to 10 CFR 51.53(c)(3)(i), an applicant for license renewal may incorporate these generic findings in its environmental report. In accordance with 10 CFR 51.53(c)(3)(ii), an environmental report must also include analyses of environmental impacts that must be evaluated on a plant
-specific basis (i.e., Category 2 issues).
In accordance with NEPA and the requirements of 10 CFR Part 51, the staff performed a plant-specific review of the environmental impacts of license renewal, including any new and significant information that the GEIS might not have considered. As part of its scoping process, the staff held two public meetings on November 5, 2009, at the Salem County Emergency Introduction and General Discussion 1-5 Services Building in Woodstown, NJ, to identify plant
-specific environmental issues that might impact Hope Creek Generating Station or Salem Nuclear Generating Station, Units 1 and 2. The staff will issue a draft plant
-specific GEIS supplement in 2010 and a final report in 2011.
1.3  Principal Review Matters Part 54 of 10 CFR describes the requirements for renewing operating licenses for nuclear power plants. The staff performed its technical review of the LRA in accordance with NRC guidance and 10 CFR Part 54 requirements. Section 54.29 of 10 CFR sets forth the standards for renewing a license. This SER describes the results of the staff's safety review.
Under 10 CFR 54.19(a), the NRC requires a license renewal applicant to submit general information. The applicant provided this general information in LRA Section 1, which it submitted by letter dated August 18, 2009. The staff reviewed LRA Section 1 and found that the applicant had submitted the information required by 10 CFR 54.19(a). Under 10 CFR 54.19(b), the staff requires that each LRA include "conforming changes to the standard indemnity agreement, 10 CFR 140.92, Appendix B, to account for the expiration term of the proposed renewed license."  The applicant stated the following in LRA Section 1.1.10 on this issue: 10 CFR 54.19(b) requires that "each application must include conforming changes to the standard indemnity agreement, 10 CFR 140.92, Appendix B, to account for the expiration term of the proposed renewed license."  The current indemnity agreements (No.P08
-046 for Salem Unit 1 and No.X08
-084 for Salem Unit 2) state in Article VII that the agreement shall terminate at the time of expiration of that license specified in Item 3 of the Attachment to the agreement, which is the last to expire; provided that, except as may otherwise be provided in applicable regulations or orders of the Commission, the term of this agreement shall not terminate until all the radioactive material has been removed from the location and transportation of the radioactive material from the location has ended as defined in subparagragh 5(b), Article I. Item 3 of the Attachment to the indemnity agreement includes license numbers, DPR
-70 and DPR
-75. Applicant requests that any necessary conforming changes be made to Article VII and Item 3 of the Attachment, and any other sections of the indemnity agreement as appropriate to ensure that the indemnity agreement continues to apply during both the terms of the current licenses and the terms of the renewed licenses. Applicant understands that no changes may be necessary for this purpose if the current license numbers are retained.
The staff intends to maintain the original license number upon issuance of the renewed license, if approved. Therefore, conforming changes to the indemnity agreement need not be made and the 10 CFR 54.19(b) requirements have been met. Under 10 CFR 54.21, the staff requires that each LRA contain:
 
Introduction and General Discussion 1-6  (a) an integrated plant assessment (IPA)
  (b) a description of any CLB changes during the staff's review of the LRA (c) an evaluation of TLAAs (d) a UFSAR supplement LRA Sections 3 and 4 and Appendix B address the license renewal requirements of 10 CFR 54.21(a), (b), and (c). LRA Appendix A satisfies the license renewal requirements of 10 CFR 54.21(d). Under 10 CFR 54.21(b), the staff requires that each year following submission of the LRA, and at least 3 months before the scheduled completion of the staff's review, the applicant submit an LRA amendment identifying any CLB changes of the facility that materially affect the contents of the LRA, including the UFSAR supplement.
Under 10 CFR 54.22, the staff requires that an applicant's LRA include changes or additions to the technical specifications necessary to manage aging effects during the period of extended operation. In LRA Section 1, the applicant stated the following:
There were no Technical Specification Changes identified necessary to manage the effects of aging during the period of extended operation.
The staff evaluated the technical information required by 10 CFR 54.21 and 10 CFR 54.22 in accordance with NRC regulations and the guidance of the SRP
-LR. SER Sections 2, 3, and 4 document the staff's evaluation of the technical information in the LRA.
As required by 10 CFR 54.25, the ACRS will issue a report to document its evaluation of the staff's LRA review and associated SER. SER Section 5 will incorporate the ACRS report once it is issued. SER Section 6 will document the findings required by 10 CFR 54.29. 1.4  Interim Staff Guidance License renewal is a living program. The staff, industry, and other interested stakeholders gain experience and develop lessons learned with each renewed license. The lessons learned address the NRC's safety goal of ensuring adequate protection of public health and safety and the environment. Interim staff guidance (ISG) is documented for use by the staff, industry, and other interested stakeholders until incorporated into such license renewal guidance documents as the SRP
-LR and the GALL Report.
Table 1.4-1 shows the current and proposed ISGs, as well as the SER sections in which they are addressed.
 
Introduction and General Discussion 1-7 Table 1.4-1  Current and Proposed Interim Staff Guidance ISG Issue (Approved ISG No.)
Purpose SER Section LR-ISG-2007-02 Changes to Generic Aging Lessons Learned (GALL) Report Aging Management Program (AMP) XI.E6, "Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements" 3.0.3.2.17 LR-ISG-2009-01 Aging Management of Spent Fuel Pool Neutron-Absorbing Materials other than Boraflex 3.0.3.3.5 1.5  Summary of the Open Item s As a result of its review of the LRA, including additional information submitted through October 15, 2010, the staff identified the following open item s (OI s). An item is considered open if, in the staff's evaluation, it does not meet all applicable regulatory requirements or the staff has not finished its review at the time of the issuance of this SER. The staff has assigned a unique identifying number to each OI.
OI 3.0.3.2.15
-1:  (SER Section 3.0.3.2.15
- Structures Monitoring Program
) The LRA states that the spent fuel pools (SFP s) have experienced leakage of borated water during refueling outages, and in
-leakage of contaminated water was noted during the field walkdown. The applicant's program for managing potential degradation of the SFP assumes that any leakage is contained completely within the leak chase channels. However, the staff requires additional information to understand the applicant's basis for concluding that such leakage is completely contained within the leak chase channels. Currently this issue is being tracked as open item as OI 3.0.3.2.15
-1. OI 3.0.3.2.1 0-1:  (SER Section s 3.0.3.2.10 and 3.0.3.3.4 - Buried Piping Inspection and Buried Non-Steel Piping Inspection Program s) LRA Section B.2.1.2 2 describes the existing Buried Piping Inspection Program as consistent, with an enhancement, with GALL AMP XI.M34, "Buried Piping and Tanks Inspection."  The applicant stated that the program provides aging management of carbon steel, galvanized steel, ductile cast iron, and gray cast iron buried piping susceptible to general corrosion, pitting, crevice corrosion, and microbiologically
-influenced corrosion. The applicant also stated that the program relies on the visual inspection of excavated piping, including the associated coatings and wrappings. The applicant further stated that there are no buried tanks within the scope of license renewal. LRA Section B.2.2.4 describes the existing Buried Non
-Steel Piping Inspection Program as a plant
-specific program. The applicant stated that the Buried Non
-Steel Piping Inspection Program is a condition monitoring program used to manage buried reinforced concrete piping and components in its service water system for cracking, loss of bond, increase in porosity and permeability, and loss of material. The Buried Non
-Steel Piping Inspection Program also manages buried stainless steel piping and components in the condensate storage and transfer system and fire protection systems for loss of material.
 
Introduction and General Discussion 1-8 Because of the recent industry events involving leakage from buried or underground piping, the staff needs additional information to evaluate how the applicant considered industry, and plant-specific operating experience in its buried piping programs. This issue remains an open item as OI 3.0.3.10-1. OI 3.1.2.2.16-1.  (SER Section 3.1.2.2.16 Cracking Due to Stress
-Corrosion Cracking and Primary Water Stress
-Corrosion Cracking
[T ube-T o-Tubesheet Welds]) The SRP-LR and GALL Report state that cracking due to primary water stress corrosion cracking (PWSCC) could occur on the primary coolant side of PWR steel steam generator (SG) tube-to-tubesheet welds made or cladded with nickel alloy; this aging effect is only addressed for once-through SGs
-not for recirculating SGs.
Given that ASME Code Section XI does not require any inspection of the tube
-to-tubesheet welds, nor does any specific NRC order or bulletin, the staff's concern is that, for Alloy 600 tubesheet cladding, the autogenous tube-to-tubesheet weld may not have sufficient chromium content to prevent the initiation of PWSCC that could propagate into/through the weld, causing a failure of the weld and reactor coolant pressure boundary for both recirculating and once
-through steam generators.
Therefore, unless the NRC has approved a redefinition of the pressure boundary in which the autogenous tube-to-tubesheet weld is no longer included, or the tubesheet cladding and welds are not susceptible to PWSCC, the staff considers that the effectiveness of the primary water chemistry program should be verified to ensure that PWSCC cracking is not occurring.
The staff is preparing a request for additional information (RAI) for the applicant to provide a plant-specific AMP that will complement the primary water chemistry program, in order to verify the effectiveness of the primary water chemistry program and ensure that cracking due to PWSCC is not occurring in tube
-to-tubesheet welds, or a rationale for why such a program is not needed. This has been identified as o pen item OI 3.1.2.2.16
-1. OI 4.3.4.2
-1  (SER Sections 3.0.3.18, 4.3.4.2 and 4.3.7.2
- Metal Fatigue of Components and Piping) During its review, the staff identified concerns regarding results of the WESTEMS program used by the applicant for aspects of the ASME Code fatigue evaluation process. For example, Westinghouse's response to NRC questions regarding the AP1000 Technical Report (see ADAMS Accession No.ML102300072, dated August 13, 2010) describes the ability of users to modify intermediate data (peak and valley stresses/times) used in the analyses. In addition, a response provided on Augu st 20, 2010 (ADAMS Accession No. ML102350440) describes different approaches for summation of moment stress terms. These items can have significant impacts on calculated fatigue cumulative usage factor (CUF) and may lead to results that are non-conservative. In addition, the staff also noted that, while the applicant selected locations per NUREG/CR
-6260 to assess the impact of the reactor coolant environment, it is not clear whether there were more limiting plant
-specific locations (e.g. locations with a higher CUF value) that were considered. Specifically, the staff is concerned whether the applicant has verified that the locations per NURE G/CR-6260 are bounding as compared to other plant
-specific locations that may have higher CUF values. This is identified as Open Item OI 4.3.4.2-1.
Introduction and General Discussion 1-9 1.6  Summary of Confirmatory Items There are no confirmatory items associated with this SER.
1.7  Summary of Proposed License Conditions Following the staff's review of the LRA, including subsequent information and clarifications provided by the applicant, the staff identified two proposed license conditions.
The first license condition requires the applicant to include the UFSAR supplement required by 10 CFR 54.21(d) in the next UFSAR update required by 10 CFR 50.71(e) following the issuance of the renewed license.
The second license condition requires the applicant to complete the commitments in the UFSAR supplement and notify the NRC in writing when implementation of those activities required prior to the period of extended operation are complete and can be verified by NRC inspection.
THIS PAGE IS INTENTIONALLY LEFT BLANK
 
2-1 SECTION 2    STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW 2.1  Scoping and Screening Methodology
 
====2.1.1 Introduction====
Title 10 of the Code of Federal Regulations, Section 54.21,(10 CFR 54.21) "Contents of Application
-Technical Information," requires for each license renewal application (LRA) an integrated plant assessment (IPA). The IPA must list and identify all of the structures, systems, and components (SSCs) within the scope of license renewal and all structures and components (SCs) subject to an aging management review (AMR), in accordance with 10 CFR 54.4. LRA Section 2.1, "Scoping and Screening Methodology," describes the scoping and screening methodology used to identify the SSCs at the Salem Nuclear Generating Station Units 1 and 2 (Salem) that are within the scope of license renewal and the SCs that are subject to an AMR. The staff reviewed the scoping and screening methodology applied by PSEG Nuclear, LLC (the applicant) to determine whether it meets the scoping requirements of 10 CFR 54.4(a) and the screening requirements of 10 CFR 54.21. In developing the scoping and screening methodology for the LRA, the applicant stated that it considered the requirements of 10 CFR Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants," (the Rule); statements of consideration related to the Rule; and the guidance of Nuclear Energy Institute (NEI) 95-10, Revision 6, "Industry Guideline for Implementing the Requirements of 10 CFR Part 54 - The License Renewal Rule," dated J une 2005. Additionally, in developing this methodology, the applicant stated that it considered the correspondence between the U.S. Nuclear Regulatory Commission (NRC or the staff), other applicants, and NEI.
2.1.2  Summary of Technical Information in the Application In LRA Section 2, "Scoping and Screening Methodology for Identifying Structures and Components Subject to Aging Management Review, and Implementation Results," and LRA Section 3, "Aging Management Review Results," the applicant provided the technica l information required by 10 CFR 54.4, "Scope," and 10 CFR 54.21(a), "An Integrated Plant Assessment."  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 the results of the process used for identifying the SCs subject to an AMR in the following LRA sections:
  (a) LRA Section 2.2, "Plant Level Scoping Results"
.
Structures and Components Subject to Aging Management Review 2-2  (b) LRA Section 2.3, "Scoping and Screening Results:  Mechanical" (c) LRA Section 2.4, "Scoping and Screening Results:  Structures" (d) LRA Section 2.5, "Scoping and Screening Results:  Electrical and Instrumentation and Controls (I&C) Systems" In LRA Section 3.0, "Aging Management Review Results," the applicant described its aging management results as follows
:  (a) LRA Section 3.1, "Aging Management of Reactor Vessels, Internals, and Reactor Coolant System"  (b) LRA Section 3.2, "Aging Management of Engineered Safety Features" (c) LRA Section 3.3, "Aging Management of Auxiliary Systems" (d) LRA Section 3.4, "Aging Management of the Steam and Power Conversion System" (e) LRA Section 3.5, "Aging Management of Containment, Structures and Component Supports"  (f) LRA Section 3.6, "Aging Management of Electrical and Instrumentation and Controls" In LRA Section 4.0, "Time
-Limited Aging Analyses," the applicant identified and described the evaluation of time
-limited aging analyses (TLAAs).
2.1.3  Scoping and Screening Program Review The staff evaluated the LRA scoping and screening methodology in accordance with the guidance contained in NUREG
-1800, Revision 1, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants" (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 (a)(2), as they relate to the methods used by the applicant to identify plant SCs subject to an AMR
 
Structures and Components Subject to Aging Management Review 2-3 As part of the review of the applicant's scoping and screening methodology, the staff reviewed the activities described in the following sections of the LRA using the guidance contained in the SRP-LR:  Section 2.1, to ensure that the applicant described a process for identifying SSCs that are within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)  Section 2.2, to ensure that the applicant described a process for determining the SCs that are subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1) and (a)(2)
In addition, the staff conducted a scoping and screening methodology audit at Salem, located at the southern end of Artificial Island in Lower Alloways Creek Township, Salem County, New Jersey, during the weeks of January 11-20, 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 implementation of the project procedures and technical basis documents 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 LRA Appendix A, "Final Safety Analysis Report Supplement," and Appendix B, "Aging Management Programs."  The staff performed a system review of the chemical and volume control system, component cooling system, radioactive drain system, auxiliary feedwater system, and the turbine building. The staff's review included a review of the applicant's reports on the scoping and screening results and the supporting design documentation used to develop the reports. The purpose of the 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  Implementing Procedures and Documentation Sources Used for Scoping and Screening The staff reviewed the applicant's scoping and screening implementing procedures as documented in the scoping and screening methodology audit trip report, dated August 25, 2010
 
(Accession No.
ML102280211), to verify that the process used to identify SCs subject to an AMR was consistent with the SRP
-LR. Additionally, the staff reviewed the scope of CLB documentation sources and the process used by the applicant to ensure that the applicant's commitments, as documented in the CLB and relative to the requirements of 10 CFR 54.4 and 10 CFR 54.21, were appropriately considered and that the applicant adequately implemented its procedural guidance during the scoping and screening process.
 
Structures and Components Subject to Aging Management Review 2-4 2.1.3.1.1  Summary of Technical Information in the Application In LRA Section 2.1, the applicant addressed the following information references for the license renewal scoping and screening process:
updated final safety analysis report (UFSAR) fire hazards analysis report environmental qualification master list maintenance rule database configurations baseline documents controlled plant component database engineering drawings engineering evaluations and calculations licensing correspondence The applicant stated that it used this information to identify the functions performed by each applicable plant system and structure. It then compared these functions to the scoping criteria in 10 CFR 54.4(a)(1)
-(3) to determine if the associated plant system or structure performed a license renewal intended function. These sources were also used to develop the list of SCs subject to an AMR.
2.1.3.1.2  Staff Evaluation Scoping and Screening Implementation Procedures. The staff reviewed the applicant's scoping and screening methodology 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 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 are consistent with the Rule, the SRP
-LR, and NEI 95
-10. 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 applicant's implementing procedures, the staff focused on the consistency of the detailed procedural guidance with information in the LRA, including the applicant's implementation of NRC staff positions documented in the SRP
-LR, and the information in the applicant's responses, dated May 28, 2010, to the staff's requests for additional information (RAIs) dated April 30, 2010.
After reviewing the LRA and supporting documentation, the staff determined that the scoping and screening methodology implementing procedures are consistent with the methodology description provided in LRA Section 2.1. The applicant's methodology has sufficient detail to provide concise guidance on the scoping and screening process to be followed during the implementation of the LRA.
 
Structures and Components Subject to Aging Management Review 2-5 Sources of Current Licensing Basis 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 bases that are docketed and in effect.
The CLB includes applicable NRC regulations, orders, license conditions, exemptions, technical specifications, and design basis information (documented in the most recent UFSAR). The CLB also includes licensee commitments remaining in effect that were made in docketed licensing correspondence, such as licensee responses to NRC bulletins, generic letters, and enforcement actions, and licensee commitments documented in NRC safety evaluations or licensee event reports. During the audit, the staff reviewed pertinent information sources used by the applicant including the UFSAR, design basis information, and license renewal boundary drawings. In addition, the applicant's license renewal process identified additional sources of plant information pertinent to the scoping and screening process, including the fire hazards analysis report, the environmental qualification master list, the maintenance rule database, the configurations baseline documents, controlled plant component database, engineering drawings, engineering evaluations and calculations, and licensing correspondence. The staff verified that the applicant's detailed license renewal program guidelines specified the use of the CLB source information in developing scoping evaluations.
The plant component database, UFSAR, quality classifications, and design basis information were the applicant's primary repository for system identification and component safety classification information used during performance of the scoping evaluations. During the audit, the staff reviewed the applicant's administrative controls for the plant component 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 selected system classification information contained in the applicable Salem documentation, the staff concludes that the applicant has established adequate measures to control the integrity and reliability of Salem system identification and safety classification data. Therefore, the staff concludes that the information sources used by Salem 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 discussed the incorporation of updates to the CLB and the process used to ensure those updates are adequately incorporated into the license renewal process. The staff determined that LRA Section 2.1 provides 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 identify SSCs 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 in ensuring that the initial scope of SSCs identified by the applicant was consistent with the plant's CLB.
Structures and Components Subject to Aging Management Review 2-6 2.1.3.1.3  Conclusion Based on 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.
2.1.3.2  Quality Controls Applied to LRA Development 2.1.3.2.1  Staff Evaluation The staff reviewed the quality assurance controls used by the applicant to ensure that scoping and screening methodologies used in the LRA were adequately implemented. The applicant applied the following quality assurance processes during the LRA development:
Written procedures were developed to govern the implementation of the scoping and screening methodology.
Scoping and screening summary reports and revisions were prepared, independently verified, and approved.
Process and procedure self
-assessment was performe
: d. Scoping and screening self
-assessment was performed.
The license renewal project team performed a self
-assessment.
The LRA was reviewed by the applicant's Challenge Board, the Plant Operations Review Committee, and the Nuclear Safety Review Board.
The LRA was benchmarked relative to recent applications.
License renewal management and staff participated in NEI license renewal activities.
License renewal management and staff participated in external industry reviews.
The staff reviewed the applicant's written procedures and documentation of assessment activities 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 guidance, discussion with the applicant's license renewal staff, and a review of the applicant's documentation of the activities performed to assess the quality of the LRA, the staff concludes that the applicant's quality assurance activities meet current regulatory requirements and provide assurance that LRA development activities were performed in accordance with the applicant's license renewal program requirements.
 
Structures and Components Subject to Aging Management Review 2-7 2.1.3.3  Training 2.1.3.3.1  Staff Evaluation The staff reviewed the applicant's training process to ensure the guidelines and methodology for the scoping and screening activities were applied in a consistent and appropriate manner. As outlined in the implementing procedures, the applicant requires training for all personnel participating in the development of the LRA and uses only trained and qualified personnel to prepare the scoping and screening implementing procedures. The training included the following activities:
License renewal staff received an initial qualification which consisted of training on the following topics:
license renewal process overview license renewal project training and reference materials relevant industry documents License renewal staff received additional classroom training on the following topics:  site document overview systems and structures overview system specific training database training License renewal process overview training was conducted at department staff meetings.
The staff reviewed the applicant's written procedures and reviewed selected completed qualification and training records for the applicant's license renewal personnel. The staff determined that the applicant had 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 supporting the process, the staff concludes that the applicant's personnel are adequately trained 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 detailed scoping and screening implementing procedures, discussions with the applicant's license renewal personnel, 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.
 
Structures and Components Subject to Aging Management Review 2-8 2.1.4  Plant Systems, Structures, and Components Scoping Methodology In LRA Section 2.1, the applicant described the methodology used to scope SSCs pursuant to the requirements of the 10 CFR 54.4(a) criteria. The LRA states that the scoping process categorized the plant in terms of major systems and structures with respect to license renewal. According to the LRA, major systems and structures were evaluated against criteria provided in 10 CFR Part 54.4 (a)(1), (2), and (3) to determine whether the item should be considered within the scope of license renewal. The LRA states that the scoping process identified the SSCs that: 
(1) are safety-related and perform or support an intended function for responding to a design-basis event (DBE), (2) are nonsafety
-related but their failure could prevent accomplishment of a safety
-related function, or (3) support a specific requirement for one of the five regulated events applicable to license renewal. LRA Section 2.0, "Scoping and Screening Methodology for Identifying Structures and Components Subject to Aging Management Review, and Implementation Results," states that the scoping methodology used by Salem is consistent with 10 CFR 54.4 and with the industry guidance contained in NEI 95
-10, Revision 6.
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 In LRA Section 2.1.3.2, "Identification of Safety
-Related Systems and Structures," the applicant stated:  Safety-related systems and structures are included in the scope of license renewal in accordance with 10 CFR 54.4(a)(1) scoping criterion. Salem systems and structures that have been classified as safety
-related are identified as "Q" in the controlled quality classification data field in the [Systems, Applications and Products in Data Processing] SAP database. Salem quality classification procedures were reviewed against the license renewal "Safety
-related" scoping criterion in 10 CFR 54.4(a)(1), to confirm that Salem safety
-related classifications are consistent with license renewal requirements. This review is included in a technical basis document. The basis document also provides a summary list of the systems and structures that are safety
-related at Salem. These systems and structures were included in the scope of license renewal under the
 
10 CFR 54.4(a)(1) scoping criteria.
The applicant further stated that the Salem quality classification procedure definition of safety-related is as follows:
Safety-Related Systems and Components
- All systems, and components necessary to ensure the integrity of the reactor coolant pressure boundary; the capability to shut down the reactor and maintain it in a safe shutdown condition; or, the capability to prevent or mitigate the consequences of postulated accidents, which could result in potential offsite doses comparable to the guideline exposure of 10 CFR 100, "Reactor Site Criteria."
The Salem procedure definition does not refer to DBEs, while 10 CFR 54.4(a)(1) refers to DBEs as defined in 10 CFR 50.49(b)(1). For Salem license renewal, an additional technical basis Structures and Components Subject to Aging Management Review 2-9 document was prepared to confirm that all applicable DBEs were considered. The basis document includes a review of all systems or structures that fall within the scope of 10 CFR 54.4(a)(1) that are relied upon to remain functional during and following DBEs as defined in 10 CFR 50.49(b)(1). This includes confirming that design basis internal and external events including design
-basis accidents (DBAs), anticipated operational occurrences, and natural phenomena as described in the CLB are considered when scoping for license renewal. Safety-related systems and structures required to perform or support 10 CFR 54.4(a)(1) functions are included within the scope of license renewal under 10 CFR 54.4(a)(1). Nonsafety-related systems and structures required to perform or support 10 CFR 54.4(a)(1) functions were included within the scope of license renewal under 10 CFR 54.4(a)(2).
The Salem quality classification procedure definition refers to 10 CFR Part 100 for accident exposure limits. The license renewal rule refers to 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or 10 CFR 100.11, as applicable. These different exposure limit requirements appear in three different code sections to address similar accident analyses performed by licensees for different reasons. The exposure limit requirements in 10 CFR 50.34(a)(1) are applicable to facilities seeking a construction permit and are, therefore, not applicable to Salem license renewal. The exposure limit requirements in 10 CFR 50.67(b)(2) are applicable to facilities seeking to revise the current accident source term used in their design basis radiological analyses. The Salem UFSAR refers to both 10 CFR 50.67 and 10 CFR Part 100 for accident exposure limits. The alternate radiological source term methodology was applied (in accordance with Regulatory Guide (RG) 1.183) to the loss
-of-coolant accident (LOCA), steam generator tube rupture, and fuel handling accident analyses and, therefore, uses 10 CFR 50.67 dose acceptance criteria. Application of alternate radiological source term methodology did not result in changes to the scope of systems classified as safety
-related using the Salem quality classification procedure.
When supplemented with the broad review of CLB DBEs, the Salem quality classification procedure definition is consistent with 10 CFR 54.4(a)(1) and results in a comprehensive list of safety-related systems and structures that were included within the scope of license renewal.
2.1.4.1.2  Staff Evaluation Pursuant to 1 0 CFR 54.4(a)(1), the applicant must consider all the safety
-related SSCs that are relied upon to remain functional during and following a DBE to ensure the following functions:  (1) the integrity of the reactor coolant pressure boundary; (2) the ability to shut down the reactor and maintain it in a safe shutdown condition; or (3) the capability to prevent or mitigate the consequences of accidents that could result in potential offsite exposures comparable to those referred to in 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or 10 CFR 100.11. With regard to identification of DBEs, SRP
-LR Section 2.1.3, "Review Procedures," states:
The set of DBEs as defined in the Rule is not limited to Chapter 15 (or equivalent) of the UFSAR. Examples of DBEs that may not be described in this chapter include external events, such as floods, storms, earthquakes, tornadoes, or hurricanes, and internal events, such as a high energy line break. Information regarding DBEs as defined in 10 CFR 50.49(b)(1) may be found in any chapter of the facility UFSAR, the Commission's regulations, NRC orders, exemptions, or license conditions within the CLB. These sources should also be reviewed to identify SSCs relied upon to remain functional during and following DBEs (as Structures and Components Subject to Aging Management Review 2-10 defined in 10 CFR 50.49(b)(1)) to ensure the functions described in 10 CFR 54.4(a)(1).
During the audit, the applicant stated that it evaluated the types of events listed in NEI 95
-10 (i.e., anticipated operational occurrences, DBAs, external events, and natural phenomena) that were applicable to Salem. 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 UFSAR and basis documents discussed events such as internal and external flooding, tornadoes, 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 provides 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 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 determined that the CLB definition of safet y-related met the definition of safety-related specified in the Rule. The staff reviewed the license renewal scoping results for the chemical and volume control system, component cooling system, radioactive drain system,  auxiliary feedwater system, and the 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 selected systems consistently with the methodology, identified the SSCs credited for performing intended functions, and adequately described the basis for the results, as well as the intended functions. The staff also verified 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.
During review of the LRA and performance of the scoping and screening methodology audit, which was performed onsite during January 11
-21, 2010, the staff determined that the scoping implementing procedures discuss the use of the classification "SR," listed in the component classification field in the Systems, Applications, and Products in Data Processing (SAP), as an initial identifier of safety
-related systems. In addition, the classification "Q," listed in the component classification field in the SAP, was also used to determine whether systems identified would be included within the scope of license renewal in accordance with 10 CFR 54.4(a)(1).
In RAI 2.1-1, dated April 30, 2010, the staff requested a detailed description of the scoping process with respect to the use of component classification fields in the SAP from the applicant. 
 
Specifically, the applicant was asked to explain how the classifications "SR" and "Q" were used to identify safety
-related systems.
On May 28, 2010, the applicant stated in response to RAI 2.1-1 that: The component design classification information is determined in accordance with the Salem classification methodology procedure SC.DE
-AP.ZZ-0061(Q),
Structures and Components Subject to Aging Management Review 2-11 "Design Classification Methodology for Component Data Module Functional Locations and Systems within SAP/R3 for Salem Generating Station."  A total of 48 design classification designations, in the form of alphanumeric codes, are used to identify the classification of components. For example, Q1 through Q20 are used for safety
-related components and F1 through F3 are used for fire protection components.
The component design classification designation provides the basis for component classifications identified in SAP, including safety classification (SAF), seismic classification (SEIS), nuclear pipe class (NUCL), quality assurance (QA), and environmental qualification (EQ) requirements. The classification methodology procedure provides the associated definitions and criteria for these classifications, and Attachment 1 of SC.DE
-AP.ZZ-0061(Q), correlates these classifications with the component design classification designation.
The "Safety related QA related" field designates safety
-related components at Salem, and is used in the Salem scoping methodology to confirm that all safety-related systems were properly identified and included in scope in accordance with 10 CF R 54.4 (a)(1) criteria. A component is designated as safety-related in the SAP database by selecting the "SR" checkbox from the input table for the "Safety related QA related" field. The value of "Safety Related" will display in the "Safety
-related QA related" field on the component classification screen in SAP. Safety
-related classifications are based on the Salem classification methodology procedure definition of safety related, as described in LRA Section 2.1.3.2. The QA Required category in SAP identifies safety
-related components that are subject to the requirements of 10 CFR 50 Appendix B "Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants." Components designated as "Safety Related" in the "Safety related QA related" SAP field described above, are also designated "Yes" in the "QA Required" field, with the unique exception of design classification designation Q18. The Q18 design classification designation applies specifically to components located in the non-seismic turbine building that serve safety
-related functions. Components designated as Q18 are nonsafety related mechanical components subject to augmented quality assurance requirements. These components were identified during the scoping process as nonsafety-related components required to support the accomplishment of a safety
-related intended function under 10 CFR 54.4(a)(1), and were, therefore, included within the scope of license renewal under 10 CFR 54.4(a)(2).
The staff reviewed the applicant's response to RAI 2.1-1 and determined that the applicant had used information contained in the component database to identify safety
-related components and the parent systems to be evaluated for inclusion within the scope of license renewal in accordance with 10 CFR 54.4(a)(1). The applicant's response indicated that the alpha
-numeric Q designations are defined by the Salem component classification methodology procedure Structures and Components Subject to Aging Management Review 2-12 SC.DE-AP.ZZ-0061(Q), which was used to classify components meeting the safety
-related criteria. In addition, during review of the LRA and performance of the scoping and screening methodology audit, the staff determined that the 10 CFR 54.4(a)(1) implementing document discusses incorrect or conservative SAP component data module (CDM) classifications. The implementing document provided the process and results of the applicant's determination that certain systems do not perform safety
-related functions as defined in 10 CFR 54.4(a)(1) and were, therefore, not included within the scope of license renewal in accordance with
 
10 CFR 54.4(a)(1).
The staff determined that additional information would be required to complete its review. In RAI 2.1-1, the staff further requested that the applicant provide a detailed description of the process used to evaluate systems or components, identified as safety
-related in the SAP, and to conclude that the SAP CDM classifications were conservative or incorrect and that the systems or components do not perform safety
-related functions as defined in 10 CFR 54.4(a)(1). On May 28, 2010, the applicant stated in response to RAI 2.1-1 that: It was recognized that this methodology could cause a system to be incorrectly classified as safety
-related for license renewal if component classification or component system assignment errors exist in SAP. It was also recognized that for some components in SAP, the component safety
-related classification basis is unrelated to the system in which it is assigned in SAP. For example, electrical components in nonsafety
-related mechanical systems will be classified safety-related if electrical faults can result in degradation of a safety
-related (1 E) power source. The component safety
-related classification is, therefore, functionally related to the 1 E power supply system, and is not functionally related to the mechanical system. These electrical components are evaluated with the associated Class 1 E electrical systems, which are also included in scope as safety
-related systems.
Results of the SAP component data review were compared to the systems identified as safetyrelated in the CLB source documents. Some components classified as safety
-related in SAP were identified in several systems, where the system is not identified as safety
-related or identified as having safety
-related intended functions in other CLB source documents, such as the UFSAR and Maintenance Rule system scoping documents. These components were reviewed in detail, and it was determined that these systems should not be identified as safetyrelated. These determinations are described in detail in the SA-SSBD-A1 basis document. Some cases involved electrical components that were classified as safety
-related based on the requirement to protect the connected safety
-related power supply system. These safety
-related electrical component classifications are not functionally related to the mechanical system, as described earlier. These electrical components are evaluated with the associate d Class 1 E electrical systems, which are included in scope as safety-related systems. This case is the result of how some electrical Structures and Components Subject to Aging Management Review 2-13 components are assigned to mechanical systems in SAP for plant operation or maintenance purposes, and is not considered a component classification discrepancy.
The remaining cases are associated with SAP component classification discrepancies such as incorrect safety classification, incorrect system assignment, or invalid SAP component identification. In each case, the correct safety classification, system assignment, or other design information was verified from other CLB source documents. Changes to existing system or component safety classifications in the CLB were not required as part of the license renewal scoping process.
The Salem component classification procedure SC.DE
-AP.ZZ-0061(Q), "Design Classification Methodology for Component Data Module Functional Locations and Systems within SAP/R3 for Salem Generating Station", requires identification of the applicable plant drawings and CLB source documents used to determine and verify component classification determinations. The SAP component classification discrepancies described above that were identified during the license renewal 10 CFR 54.4 (a)(1) scoping reviews were determined to be SAP errors and are not plant design issues, because the correct classifications are identified in the applicable CLB source documents. Actions were initiated to notify station personnel and correct the SAP data. SAP errors considered
 
non-conservative or otherwise adverse to quality were entered into the corrective action process to correct the error.
Based on its review, the staff finds the applicant's response to RAI 2.1-1 acceptable because the applicant had described the process used to evaluate systems which contained components, identified as safety
-related in the SAP and within the scope of license renewal in accordance with 10 CFR 54.4(a)(1). Also, the staff notes that the re could be some components incorrectly classified as safety
-related for license renewal if component classification or component system assignment errors exist in SAP and for some components in SAP, the component safety
-related classification basis is unrelated to the system in which it is assigned in SAP. The staff determines that the applicant's methodology for identifying systems and structures is acceptable because if inconsistencies do exist with SAP, the applicant will verify the correct safety classification, system assignment, or other design information with the CLB source documents and actions will be initiated to notify station personnel an d enter the component into the corrective action process to correct the SAP data. The staff's concern described in RAI 2.1-1 is resolved.
2.1.4.1.3  Conclusion On the basis of its review of systems, discussions with the applicant, review of the applicant's scoping process, and the response to RAI 2.1-1, the staff concludes that the applicant's methodology for identifying systems and structures is consistent with the SRP
-LR and 10 CFR 54.4(a)(1) and, therefore, is acceptable.
 
Structures and Components Subject to Aging Management Review 2-14 2.1.4.2  Application of the Scoping Criteria in 10 CFR 54.4(a)(2) 2.1.4.2.1  Summary of Technical Information in the Application In LRA Section 2.1.3.3, "10 CFR 54.4(a)(2) Scoping Criteria," the applicant stated:
All nonsafety
-related systems, structures, and components whose failure could prevent satisfactory accomplishment of any of the functions identified under 10 CFR 54.4 (a)(1), were included in the scope of license renewal in accordance with 10 CFR 54.4(a)(2) requirements. To assure complete and consistent application of this scoping criterion, a technical basis document was prepared.
This license renewal scoping criterion requires consideration of the following:
: 1. Nonsafety-related SSCs required to support a safety
-related 10 CFR 54.4(a)(1) function
: 2. Nonsafety-related systems connected to and providing structural support for a safety
-related SSC
: 3. Nonsafety-related systems with a potential for spatial interaction with safety-related SSCs.
In LRA Section 2.1.5.2, "Nonsafety
-Related Affecting Safety
-Related - 10 CFR 54.4(a)(2)," the applicant stated:
Functional Support for Safety
-Related SSC 10 CFR 54.4(a)(1) Functions. This category addresses nonsafety
-related SSCs that are required to function in support of a safety
-related SSC intended function. The functional requirement distinguishes this category from the next two categories, where the nonsafety-related SSCs are required only to maintain adequate integrity to preclude structural failure or spatial interactions. The nonsafety
-related SSCs that were included in scope under this review, to support a safety
-related SSC in performing its 10 CFR 54.4(a)(1) intended function, are identified on the license renewal boundary drawings in green. The Salem UFSAR and other CLB documents were reviewed to identify nonsafety
-related systems or structures credited with supporting satisfactory accomplishment of a safety
-related function. Nonsafety-related systems or structures credited in CLB documents to support a safety-related function have been included within the scope of license renewal
. Connected to and Provide Structural Support for Safety
-related SSCs. For nonsafety-related piping connected to safety
-related piping, the nonsafety
-related piping was assumed to provide structural support to the safety
-related piping, unless otherwise confirmed by a review of the installation details. The nonsafety-related piping was included in scope for 10 CFR 54.4(a)(2), from the safety-related/nonsafety-related interface, to one of the following:
 
Structures and Components Subject to Aging Management Review 2-15 A seismic anchor. Only true anchors that ensure forces and moments are restrained in three orthogonal directions are credited.
An anchored component (e.g., pump, heat exchanger, tank, etc.) that is desig ned not to impose loads on connecting piping. The anchored component is included in scope of license renewal as it has a structural support function for the safety-related piping.
A flexible hose or flexible joint that is not capable of load transfer.
A free end of nonsafety
-related piping, such as a drain pipe that ends at an open floor drain.
For nonsafety
-related piping runs that are connected at both ends to safety-related piping, the entire run of nonsafety
-related piping is included in scope. A branch line off of a header where the moment of inertia of the header is greater than 15 times the moment of inertia of the branch. The header is treated as an anchor. These scoping boundaries are determined from review of the physical installation details, design drawings or seismic analysis calculations.
Potential for Spatial Interactions with Safety
-Related SSCs
. Nonsafety-related systems that are not connected to safety
-related piping or components, or are beyond the first seismic anchor point past the safety/nonsafety interface, and have a spatial relationship such that their failure could adversely impact the performance of a safety
-related SSC intended function, must be evaluated for license renewal scope in accordance with 10 CFR 54.4(a)(2) requirements. As described in NEI 95
-10 Appendix F, there are two options when performing this scoping evaluation:  a mitigative option and a preventive option.
The preventive option involves identifying the nonsafety
-related SSCs that have a spatial relationship such that failure could adversely impact the performance of a safety-related SSC intended function, and including the identified nonsafety-related SSC in the scope of license renewal without consideration of plant mitigative features. Salem applied the preventive option for 10 CFR 54.4(a)(2) scoping.
2.1.4.2.2  Staff Evaluation Pursuant to 10 CFR 54.4(a)(2), the applicant must consider all nonsafety
-related SSCs whose failure could prevent the satisfactory accomplishment of safety
-related functions of SSCs relied on to remain functional during and following a DBE to ensure:  (1) the integrity of the reactor coolant pressure boundary, (2) the ability to shut down the reactor and maintain it in a safe shutdown condition, or (3) the capability to prevent or mitigate the consequences of accidents that could result in potential offsite exposures comparable to those referred to in
 
10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or 10 CFR 100.11.
Structures and Components Subject to Aging Management Review 2-16 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 including:  (1) nonsafety-related SSCs typically identified in the CLB; (2) consideration of missiles, cranes, flooding, and high
-energy line breaks (HELBs); (3) nonsafety-related SSCs connected to safety
-related SSCs; (4) nonsafety-related SSCs in proximity to safety
-related SSCs; and (5) mitigative and preventive options related to nonsafety
-related and safety
-related SSCs interactions.
In addition, as discussed in NEI 95
-10, Revision 6, the applicants should not consider hypothetical failures, but rather should base their evaluation on the plant's CLB, engineering judgment and analyses, and relevant operating experience. NEI 95
-10 further describes operating experience as all documented plant-specific and industry
-wide experience that can be used to determine the plausibility of a failure. Documentation would include NRC generic communications and event reports, plant
-specific condition reports, industry reports such as safety operational event reports, and engineering evaluations. The staff reviewed LRA Sections 2.1.3.3 and 2.1.5.2 in which the applicant described the scoping methodology for nonsafety-related SSCs pursuant to 10 CFR 54.4(a)(2). In addition, the staff reviewed the applicant's 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 Sections 2.1.3.3 and 2.1.5.2 and the applicant's 10 CFR 54.4(a)(2) implementing document. The staff verified that the applicant had reviewed the UFSAR, plant drawings, plant component 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 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 verified 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 the LRA and the applicant's 10 CFR 54.4(a)(2) implementing document. The applicant had reviewed the interfaces in each mechanical system between safety
-related sections and nonsafety
-related sections for the purpose of identifying th e nonsafety-related components located between the interface and license renewal 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:
 
Structures and Components Subject to Aging Management Review 2-17  seismic anchors bounding conditions described in NEI 95
-10 Revision 6, Appendix F, such as base-mounted component, flexible connection, free end of nonsafety
-related piping, or inclusion of the entire nonsafety
-related piping run Nonsafety-Related SSCs with the Potential for Spatial Interaction with Safety
-Related SSCs. The staff verified 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 LRA Section 2.1.5.2 and the applicant's 10 CFR 54.4(a)(2) implementing procedure. The applicant had 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 verified that the applicant used a spaces approach to identify the portions of nonsafety-related systems with the potential for spatial interaction with safety
-related SSCs.
The spaces approach is a scoping process, which involves an evaluation based on equipment location and the related SSCs and whether or not fluid
-filled system components are located in the same space as safety
-related equipment. A space was defined as a structure containing active or passive safety
-related SSCs, for the purposes of the review.
LRA Section 2.1.5.2 and the applicant's implementing document state that the applicant had 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 had evaluated all nonsafety
-related SSCs, containing liquid or steam, and located in spaces containing safety
-related SSCs. The applicant used a spaces approach as described above to identify the nonsafety
-related SSCs that were located within the same space as 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 walkdowns. Nonsafety
-related systems and components that contain liquid or steam and located inside structures that contain safety
-related SSCs were included within the scope of license renewal, unless it was in an excluded space. 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 verified that those nonsafety-related SSCs determined to contain liquid or steam and located within a space containing safety
-related SSCs were included within the scope of license renewal, in accordance with 10 CFR 54.4(a)(2).
2.1.4.2.3  Conclusion On the basis of its review of the applicant's scoping process, discussions with the applicant, and review of the information provided in the response to RAI 2.1-1, 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.
 
Structures and Components Subject to Aging Management Review 2-18 2.1.4.3  Application of the Scoping Criteria in 10 CFR 54.4(a)(3) 2.1.4.3.1  Summary of Technical Information in the Application In LRA Section 2.1.5.3, "Regulated Events
- 10 CFR 54.4(a)(3)," the applicant stated
:  For each of the five regulations (i.e., fire protection, environmental qualification, anticipated transients without scram, station blackout, and pressurized thermal shock), a technical basis document was prepared to provide input into the scoping process. Each of the regulated event basis documents identify the systems and structures that are relied upon to demonstrate compliance with the applicable regulation. The basis documents also identify the source documentation used to determine the scope of components within the system that are credited to demonstrate compliance with each of the applicable regulated events. SSCs credited in the regulated events have been classified as satisfying criteria of 10 CFR 54.4(a)(3) and have been included within the scope of license renewal Fire Protection. In LRA Section 2.1.3.4, "Scoping for Regulated Events," subSection "Fire Protection," the applicant stated:
All systems, structures and components (SSCs) 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 the fire protection program to comply with the requirements of 10 CFR 50.48 includes:
systems and structures required to demonstrate post
-fire safe shutdown capabilities systems and structures required for fire detection and suppression systems and structures required to meet commitments made to Appendix A of Branch Technical Position (BTP) APCSB 9.5
-1 The fire protection technical basis document summarizes results of a detailed review of the plant's fire protection program documents that demonstrate compliance with the requirements of 10 CFR 50.48. The basis document provides a list of systems and structures credited in the plant's fire protection program documents. For the listed systems and structures, the basis document also identifies appropriate CLB references. The identified systems and structures are included in the scope of license renewal under the 10 CFR 54.4(a)(3) scoping criteria.
 
Structures and Components Subject to Aging Management Review 2-19 Environmental Qualification. In LRA Section 2.1.3.4, subSection "Environmental Qualification," the applicant stated:
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 Environmental Qualification (10 CFR 50.49) be included in the scope of license renewal.
The Salem Environmental Qualification (EQ) program includes safety
-related electrical equipment, nonsafety
-related electrical equipment whose failure under postulated environmental conditions could prevent satisfactory accomplishment of safety functions of the safety
-related equipment, and certain post
-acciden t monitoring equipment, as defined in 10 CFR 50.49(b)(1), 10 CFR 50.49(b)(2), and 10 CFR 50.49(b)(3) respectively. This equipment is included in the scope of license renewal.
Anticipated Transient without Scram. In LRA Section 2.1.3.4, subSection "Anticipated Transients Without Scram," the applicant stated:
Anticipated Transients Without Scram (ATWS) is a postulated operational transient that generates an automatic scram signal, accompanied by a failure of the reactor protection system to shutdown the reactor. The ATWS rule (10 CFR 50.62) requires improvements in the design and operation of pressurized water reactors to reduce the likelihood of failure to shutdown the reactor following anticipated transients, and to mitigate the consequences of an ATWS event. The requirements for a PWR are to have equipment from sensor output to final actuation device, which is diverse from the Reactor Protection System, to automatically initiate the auxiliary feedwater system and initiate a turbine trip under conditions indicative of an ATWS.
The ATWS basis document summarizes the results of a review of the Salem current licensing basis with respect to ATWS. Salem has the ATWS Mitigation System Actuation Circuitry (AMSAC), which comprises a diverse scram system to mitigate the consequences of an ATWS event. The ATWS basis document provides a list of the systems required by 10 CFR 50.62 to reduce the risk from ATWS events. The basis document also provides a list of structures that are credited to provide physical support and protection for the credited ATWS systems. These systems and structures are included in the scope of license renewal under the 10 CFR 54.4(a)(3) scoping criteria.
Station Blackout. In LRA Section 2.1.3.4, subSection "Station Blackout," the applicant stated:  Salem implemented plant modifications and procedures in response to
 
10 CFR 50.63 to enable the station to withstand and recover from a station blackout as an AC
-independent, four
-hour coping plant. Salem capabilities, commitments and analyses that demonstrate compliance with 10 CFR 50.63 are Structures and Components Subject to Aging Management Review 2-20 documented in UFSAR Section 3.12, and in NRC safety evaluation reports and correspondence related to the [station blackout] (SBO) rule.
The NUREG-1800 guidance on scoping of equipment relied on to meet the requirements of the SBO rule (10 CFR 50.63) for license renewal has been incorporated into the Salem scoping methodology. In accordance with the NUREG-1800 requirements, the SSCs required to recover from the SBO event are included in the scope of license renewal. Recovery is defined as the re-powering of the plant AC distribution system from offsite sources or onsite emergency AC sources.
The SBO basis document summarizes the results of a review of the Salem current licensing basis with respect to station blackout. The basis document provides lists of systems and structures credited in Salem SBO evaluations. For the listed systems and structures, the basis document also identifies appropriate CLB references. These systems and structures are included in the scope of license renewal under the 10 CFR 54.4(a)(3) scoping criteria.
Pressurized Thermal Shock. In LRA Section 2.1.3.4, subSection "Pressurized Thermal Shock," the applicant stated:
Pressurized Thermal Shock (PTS) is a potential pressurized water r eactor (PWR) event or transient causing vessel failure due to severe overcooling (thermal shock) concurrent with, or followed by, significant pressure in the reactor vessel. The CLB shows that the Salem reactor vessel has been demonstrated to meet the toughness requirements of 10 CFR 50.61 through its current 40
-year end-of license period. Sixty
-year end-of-license fluence projections were prepared, and the components that are projected to meet the definition of beltline material after 60 years of neutron exposure were identified.
The PTS basis document summarizes the results of a review of the Salem current licensing basis with respect to pressurized thermal shock. The basis document identifies components within the Reactor Vessel that are credited in Salem PTS evaluations. The Reactor Vessel is included in the scope of license renewal under the 10 CFR 54.4(a)(3) scoping criteria.
2.1.4.3.2  Staff Evaluation The staff reviewed the applicant's approach to identifying SSCs relied upon to perform functions meeting the requirements of the fire protection, EQ, ATWS, SBO, and PTS regulations. As part of this review, the staff discussed the methodology with the applicant, reviewed the documentation developed to support the approach, and evaluated mechanical systems and structures included within the scope of license renewal pursuant to 10 CFR 54.4(a)(3).
Fire Protection. The staff determined that the applicant's implementing procedures indicated that it had included systems and structures in the scope of license renewal required for post
-fire safe shutdown, fire detection suppression, and commitments made to Appendix A of Structures and Components Subject to Aging Management Review 2-21 BTP APCSB 9.5-1, "Guidelines for Fire Protection for Nuclear Power Plants Docketed Prior to July 1, 1976," issued May 1976. The applicant noted that it had considered CLB documents to identify systems and structures within the scope of license renewal. These documents included 10 CFR 50, Appendix R, "Fire Study and Salem's Fire Protection Plan"; fire protection systems scoping and screening basis document; fire hazards analysis report; the fire protection program plan as required by 10 CFR 50.48; UFSAR; drawings; and other Salem technical basis documents. The staff reviewed selected scoping results in conjunction with the LRA and the CLB information to validate the methodology for including the appropriate systems and structures within the scope of license renewal. Based on its review of the CLB documents and the selected reviews, the staff determined that the applicant's scoping methodology was adequate for identifying SSCs credited in performing fire protection functions in accordance with
 
10 CFR 50.48 and within the scope of license renewal.
Environmental Qualification. The staff verified that the applicant's implementing procedures 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), (b)(2), and (b)(3). The staff reviewed the LRA, implementing procedures, the EQ systems scoping and screening basis document and the EQ master component equipment list to verify that the applicant identified SSCs within the scope of license renewal and subject to EQ requirements. Based on that review, the staff determined that the applicant's scoping methodology is adequate for identifying SSCs that meet the requirements of 10 CFR 50.49 within the scope of license renewal.
Anticipated Transient Without Scram. The staff determined that the applicant had generated a list of plant systems credited for ATWS mitigation based on review of the plant and the ATWS systems scoping and screening documents, the UFSAR, docketed correspondence, modifications, and the plant component database. The staff reviewed these documents and the LRA in conjunction with the scoping results to validate the methodology for identifying ATWS systems and structures that are within the scope of license renewal. The staff determined that the applicant's scoping methodology was adequate for identifying SSCs that meet the requirements of 10 CFR 50.62 and are within the scope of license renewal.
Station Blackout. The staff determined that the applicant identified those systems and structures associated with coping and safe shutdown of the plant following an SBO event by reviewing plant
-specific SBO systems, scoping and screening basis document calculations, the UFSAR, drawings, modifications, the plant component database, and plant procedures. The staff reviewed selected documents and the LRA in conjunction with the scoping results to validate the applicant's methodology. The staff finds that the scoping results included systems and structures that perform intended functions meeting 10 CFR 50.63 requirements. The staff determined that the applicant's scoping methodology was adequate for identifying SSCs credited as meeting the requirements of 10 CFR 50.63 and are within the scope of license renewal. Pressurized Thermal Shock. The staff determined that the applicant's scoping methodology had required the applicant to review the activities performed to meet 10 CFR 50.61. As a result of the applicant's methodology, these systems and structures are considered to be within the scope of license renewal pursuant to 10 CFR 54.4(a)(3). The staff reviewed the PTS scoping and screening basis document and the implementing procedure and determined that the methodology was appropriate for identifying SSCs with functions credited for complying with the Structures and Components Subject to Aging Management Review 2-22 PTS regulation and within the scope of license renewal. The staff finds that the scoping results included the systems and structures that perform intended functions to meet the requirements of 10 CFR 50.61. Accordingly, the staff determined that the applicant's scoping methodology was adequate for including SSCs that meet the requirements of 10 CFR 50.61 and are within the scope of license renewal.
2.1.4.3.3  Conclusion On the basis of the discussion with the applicant, review of the LRA, and review of the implementing procedures and reports, the staff concludes that the applicant's methodology for identifying systems and structures meets the scoping criteria pursuant to 10 CFR 54.4(a)(3) and, therefore, is acceptable.
2.1.4.4  Plant-Level Scoping of Systems and Structures 2.1.4.4.1  Summary of Technical Information in the Application In LRA Section 2.1, "Scoping and Screening Methodology," the applicant stated:
The initial step in the scoping process was to define the entire plant in terms of systems and structures. These systems and structures were evaluated against the scoping criteria in 10 CFR 54.4(a)(1), (a)(2), and (a)(3), to determine if they perform or support a safety
-related intended function, or perform functions that demonstrate compliance with the requirements of one of the five license renewal regulated events. For the systems and structures determined to be in scope, the intended functions that are the bases for including the systems and structures in scope were also identified. Scoping evaluations are documented in a System or Structure Scoping Report.
If any portion of a system or structure met the scoping criteria of 10 CFR 54.4, the system or structure was included in the scope of license renewal. Mechanical systems and structures were then further evaluated to determine those mechanical and structural components that perform or support the identified intended functions. The in scope boundaries of mechanical systems and structures were developed. These boundaries are also depicted on the license renewal boundary drawings. The boundaries of the mechanical systems and structures within the scope of license renewal are highlighted in color. In scope structures and mechanical components are shown in green, except nonsafety-related mechanical components that are within the scope of license renewal to preclude physical or spatial interaction, or provide structural support to safety-related SSCs, which are shown in red.
All electrical components within the in scope mechanical and electrical systems were included in the scope of license renewal as electrical commodities. Consequently, further system evaluations to determine which electrical components were required to perform or support the system intended functions were not required.
 
Structures and Components Subject to Aging Management Review 2-23 LRA Section 2.1.2, "Information Sources Used for Scoping and Screening," states that the UFSAR, fire hazards analysis report, EQ master list, and maintenance rule database were the primary sources of information used during the scoping process.
LRA Section 2.1.6.3, "Stored Equipment," states that the equipment that is stored on site for installation in response to a DBE is considered to be within the scope of license renewal. At Salem, certain Appendix R fire scenarios used stored equipment to facilitate repairs following the fire. The stored equipment credited for Appendix R repairs are listed in controlled station procedures. These components are confirmed to be available and in good operating condition by periodic surveillance inspections.
LRA Section 2.1.6.4, "Consumables," states that the evaluation process for consumables is consistent with the guidance provided in NUREG
-1800, Table 2.1
-3. Consumables have been divided into the following four categories for the purpose of license renewal:  (1) packing, gaskets, component seals, and O
-rings; (2) structural sealants; (3) oil, grease, and component filters; and (4) system filters, fire extinguishers, fire hoses, and airpacks. 2.1.4.4.2  Staff Evaluation The staff reviewed the applicant's methodology for performing the scoping of plant systems and components to ensure it was consistent with 10 CFR 54.4. The methodology used to determine the systems and components within the scope of license renewal was documented in implementing procedures and scoping results reports for 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 staff reviewed the LRA and applicable implementing procedures that addressed the process used to evaluate stored equipment, credited for response to a DBE, for inclusion within the scope of license renewal. The staff determined that the applicant had appropriately considered stored equipment and included it within the scope of license renewal. In addition, the staff reviewed the LRA and applicable implementing procedures that addressed the process used to evaluate consumables for inclusion within the scope of license renewal. The staff determined that the applicant had appropriately determined that structural sealants were included within the scope of license renewal.
The applicant documented the results of the plant
-level scoping process in accordance with the implementing procedures. The results were provided in the systems and structures documents and reports which contained information including a description of the structure or system, a listing of functions performed by the system or structure, identification of intended functions, the
 
10 CFR 54.4(a) scoping criteria met by the system or structure, references, and the basis for the classification of the system or structure intended functions. During the audit, the staff reviewed selected documents and reports and concluded that the applicant's scoping results contained an appropriate level of detail to document the scoping process.
 
Structures and Components Subject to Aging Management Review 2-24 2.1.4.4.3  Conclusion Based on its review of the LRA, implementing procedures, reports, and selected system scoping results reviewed 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 Component Scoping 2.1.4.5.1  Summary of Technical Information in the Application In addition to the information previously discussed in SER Section 2.1.4.4.1, LRA Section 2.1.5, "Scoping Procedure," states:
The scoping process is the systematic process used to identify the systems, structures, and components within the scope of the license renewal rule. The scoping process was initially performed at the system and structure level, in accordance with the scoping criteria identified in 10 CFR 54.4(a). System and structure functions and intended functions were identified from a review of the source CLB documents. In scope boundaries were established and documented in the scoping evaluations, based on the identified intended functions. The in scope boundaries form the basis for identification of the in scope components, which is the first step in the screening process. System and structure scoping evaluations are documented and have been retained in a license renewal database.
In LRA Section 2.1.5.5, "Scoping Boundary Determination," the applicant stated:
For mechanical systems, the mechanical components that support the system intended functions are included in the scope of license renewal and are depicted on the applicable system piping and instrumentation diagram. Mechanical system piping and instrumentation diagrams are marked up to create license renewal boundary drawings showing the in scope components. Components that are required to support a safety
-related function, or a function that demonstrates compliance with one of the license renewal regulated events, are identified on the system piping and instrumentation diagram by green highlighting. Nonsafety
-related components that are connected to safety
-related components and are required to provide structural support at the safety/nonsafety interface, or components whose failure could prevent satisfactory accomplishment of a safety
-related function due to spatial interaction with safety-related SSCs, are identified by red highlighting. A computer sort and download of associated system components from the SAP database confirms the scope of components in the system. Plant walkdowns were performed when required for additional confirmation.
Structures and Components Subject to Aging Management Review 2-25 2.1.4.5.2  Staff Evaluation The staff used the SRP
-LR to evaluate LRA Sections 2.1.5 and 2.1.5.5 and the applicant's guidance in the implementing procedures and reports to perform the review of the mechanical scoping process. The implementing procedures and reports provided instructions for identifying the evaluation boundaries. Information related to system operations in support of the intended functions was necessary to determine the mechanical system evaluation boundary. Based on the review of the implementing procedures and the CLB documents associated with mechanical system scoping, the staff determined that the guidance and CLB source information noted above were consistent with the information in the LRA for identifying mechanical components and support structures in mechanical systems that are within the scope of license renewal.
The staff conducted detailed discussions with the applicant's license renewal project personnel and reviewed documentation pertinent to the scoping process. The staff assessed whether the applicant had appropriately applied the scoping methodology outlined in the LRA and implementing procedures and whether the scoping results were consistent with CLB requirements. The staff determined that the applicant's procedure was consistent with the description provided in LRA Sections 2.1.5 and 2.1.5.5 and the guidance contained in SRP
-LR Section 2.1 was adequately implemented.
The staff selected and reviewed the scoping reports for the chemical and volume control system, component cooling system, radioactive drain system, and auxiliary feedwater system for mechanical component types that met the scoping criteria of 10 CFR 54.4. The staff verified that the applicant had identified and used pertinent engineering and licensing information in order to determine the mechanical component types required to be within the scope of license renewal. As part of the review process, the staff evaluated:  (1) each system's intended functions identified for the chemical and volume control system, component cooling system, radioactive drain system, and auxiliary feedwater system;  (2) the basis for inclusion of the intended function, and (3) the process used to identify each of the system component types. The staff verified that the applicant had identified and highlighted system drawings to develop the license renewal boundaries in accordance with the procedural guidance. Additionally, the staff determined that the applicant had performed an independent verification of the results in accordance with the governing procedures. The staff verified that the applicant had license renewal personnel knowledgeable about the system and these personnel had performed independent reviews of the highlighted drawings to ensure accurate identification of syste m intended functions. The staff also verified that the applicant had 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 and supporting documents, discussion with the applicant, and the system review 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.
2.1.4.6  Structural Component Scoping 2.1.4.6.1  Summary of Technical Information in the Application In LRA Section 2.1.5, the applicant stated:
 
Structures and Components Subject to Aging Management Review 2-26 The scoping process is the systematic process used to identify the systems, structures and components within the scope of the license renewal rule. The scoping process was initially performed at the system and structure level, in accordance with the scoping criteria identified in 10 CFR 54.4(a). System and structure functions and intended functions were identified from a review of the source CLB documents. In scope boundaries were established and documented in the scoping evaluations, based on the identified intended functions. The in scope boundaries form the basis for identification of the in scope components, which is the first step in the screening process. System and structure scoping evaluations are documented and have been retained in a license renewal database.
In LRA Section 2.1.5.5, the applicant stated:
For structures, the structural components that support the intended functions are included in the scope of license renewal. The structural components are identified from a review of applicable plant design drawings of the structure. Plant walkdowns were performed when required for additional confirmation. A single site plan layout drawing is marked up to create a license renewal boundary drawing showing the structures in the scope of license renewal.
2.1.4.6.2  Staff Evaluation The staff evaluated LRA Sections 2.1.5 and 2.1.5.5, and subsections, and the guidance contained in the applicant's implementing procedures and reports to perform the review of the structural scoping process. 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 selected 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 component database, the Structures Monitoring Program, UFSAR, controlled drawings, maintenance procedures, and walkdowns. Each structure the applicant identified was evaluated against the criteria of 10 CFR 54.4(a)(1), (a)(2), and (a)(3).
The staff reviewed selected portions of the plant component database, UFSAR, drawings, procedures, and implementing procedures to verify the adequacy of the methodology. The staff selected and reviewed the source documentation for the turbine building to verify that the application of the methodology would provide the results as documented in the turbine building scoping report and in the LRA. The staff verified that the applicant had identified and used pertinent engineering and licensing information in order to determine that the turbine building was required to be included within the scope of license renewal. In addition, during the scoping and screening methodology audit, the staff performed walkdowns of selected areas of the turbine building to verify proper implementation of the scoping process. As part of the review process, the staff evaluated the intended functions identified for the turbine building and the structural components, the basis for inclusion of the intended function, and the process used to identify each of the component types.
 
Structures and Components Subject to Aging Management Review 2-27 2.1.4.6.3  Conclusion On the basis of its review of information in the LRA and supporting documents, implementing procedures, and structural scoping results, the staff concludes that the applicant's methodology for 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 In LRA Section 2.1.5, the applicant stated:
The scoping process is the systematic process used to identify the systems, structures and components within the scope of the license renewal rule. The scoping process was initially performed at the system and structure level, in accordance with the scoping criteria identified in 10 CFR 54.4(a). System and structure functions and intended functions were identified from a review of the source CLB documents. In scope boundaries were established and documented in the scoping evaluations, based on the identified intended functions. The in scope boundaries form the basis for identification of the in scope components, which is the first step in the screening process. System and structure scoping evaluations are documented and have been retained in a license renewal database.
In LRA Section 2.1.5.5, the applicant stated:
Electrical and I&C systems, and electrical components within mechanical systems, did not require further system evaluations to determine which components were required to perform or support the identified intended functions. A bounding scoping approach is used for electrical equipment. All electrical components within in scope systems were included in the scope of license renewal. In scope electrical components were placed into commodity groups and were evaluated as commodities during the screening process.
2.1.4.7.2  Staff Evaluation The staff evaluated LRA Sections 2.1.5 and 2.1.5.5, and subsections, and the guidance contained in the applicant's 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, plant component database, CLB documentation, drawings, and specifications. 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 selected SSCs that were identified within the scope of license renewal. The staff determined that the applicant had included electrical and instrument control components, Structures and Components Subject to Aging Management Review 2-28 including components contained in the 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, implementing procedures and supporting documents, discussions with the applicant, and a review of selected electrical scoping results, the staff concludes that the applicant's methodology for the identification of electrical and I&C SSCs within the scope of license renewal is in accordance with the requirements of 10 CFR 54.4 and, therefore, is acceptable.
2.1.4.8  Scoping Methodology Conclusion On the basis of its review of the LRA, implementing procedures, and a review of selected 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:  (1) that are safety-related, (2) whose failure could affect safety
-related functions, and (3) that are necessary to demonstrate compliance with the NRC regulations for fire protection, EQ, pressurized thermal shock, ATWS, and SBO. The staff concludes that the applicant's methodology is consistent with the requirements of 10 CFR 54.4(a) and, therefore, is acceptable.
2.1.5  Screening Methodology 2.1.5.1  General Screening Methodology 2.1.5.1.1  Summary of Technical Information in the Application LRA Section 2.1.6.1, "Identification of Structures and Components Subject to AMR," and subsections, describes the screening process that identifies the SCs within the scope of license renewal that are subject to an AMR. In LRA Section 2.1.6.1, the applicant stated
:  Structures and components 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 procedure is the process used to identify the passive, long
-lived structures and components in the scope of license renewal and subject to aging management review.
NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants" 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 and, if applicable, on the associated license renewal boundary drawing. The Salem structures and components Structures and Components Subject to Aging Management Review 2-29 subject to AMR have been identified in accordance with the requirements of 10 CFR 54.21(a)(1) described above.
2.1.5.1.2  Staff Evaluation Pursuant to 10 CFR 54.21, each LRA must contain an IPA that identifies SCs within the scope of license renewal that are subject to an AMR. The IPA must identify components that perform an intended function without moving parts or a change in configuration or properties (passive), as well as components that are not subject to periodic replacement based on a qualified life or specified time period (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 operatio
: n. 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 2.1.6.1, the applicant discussed these screening activities as they relate 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:  Containment, Structures and Components Supports"
; and LRA Section 2.5, "Scoping and Screening Results:  Electrical and Instrumentation and Controls (I&C) Systems."  These LRA sections provide the results of the process used to identify component types and commodity groups subject to an AMR. 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 staff also reviewed the screening results reports for the chemical and volume control system, component cooling system, radioactive drain system, auxiliary feedwater system, and the turbine building.
2.1.5.1.3  Conclusion On the basis of its review of the LRA, the implementing procedures, and selected screening results, the staff concludes that the applicant's screening methodology was consistent with the guidance contained in the SRP
-LR and was capable of identifying passive, long
-lived components 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 subject to an AMR is consistent with the requirements of 10 CFR 54.21 and, therefore, is acceptable.
 
Structures and Components Subject to Aging Management Review 2-30 2.1.5.2  Mechanical Component Screening 2.1.5.2.1  Summary of Technical Information in the Application In LRA Section 2.1.6.1, "Identification of Structures and Components Subject to AMR," the applicant stated:
For in scope mechanical systems, the completed scoping packages include written descriptions and marked up system piping and instrumentation diagrams that clearly identify the in scope system boundary for license renewal. The marked up system piping and instrumentation diagrams are called boundary drawings for license renewal. These system boundary drawings were carefully reviewed to identify the passive, long
-lived components, and the identified components were then entered into the license renewal database. Component listings from the SAP database were also reviewed to confirm that all system components were considered. In cases where the system piping and instrumentation diagram did not provide sufficient detail, such as for some large vendor supplied components (e.g., compressors, emergency diesel generators), the associated component drawings or vendor manuals were also reviewed. Plant walkdowns were performed when required for confirmation. Finally, the identified list of passive, long
-lived system components was benchmarked against previous license renewal applications containing a similar system
. 2.1.5.2.2  Staff Evaluation The staff reviewed the mechanical screening methodology discussed and documented in LRA Section 2.1.6.1, implementing procedures, scoping and screening reports, and license renewal drawings. The staff determined that the mechanical system screening process used the results from the scoping process and that the applicant reviewed each system evaluation boundary as depicted on system drawings to identify passive and long
-lived components.
Additionally, the staff determined that the applicant had identified all passive and 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 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 system drawings.
The staff verified 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.
The staff reviewed portions of the UFSAR, plant component database, CLB documentation, procedures, drawings, specifications, and selected scoping and screening reports. The staff conducted detailed discussions with the applicant's license renewal team and reviewed Structures and Components Subject to Aging Management Review 2-31 documentation pertinent to the screening process. The staff assessed whether the mechanical screening methodology outlined in the LRA and implementing procedures was appropriately implemented and if the scoping results were consistent with CLB requirements. During the scoping and screening methodology audit, the staff discussed the screening methodology with the applicant and reviewed the applicant's screening reports for the chemical and volume control system, component cooling system, radioactive drain system, and auxiliary feedwater system to verify proper implementation of the screening process. In addition, the staff performed walkdowns of selected portions of the systems as an example of the methodology and its implementation. Based on these 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 component database, CLB documentation, procedures, drawings, specifications
, selected scoping and screening reports, and a review of the results for selected systems, 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 C FR 54.21(a)(1) and, therefore, is acceptable.
2.1.5.3  Structural Component Screening 2.1.5.3.1  Technical Information in the Application In LRA Section 2.1.6.1, the applicant stated:
For in scope structures, the completed scoping packages include written descriptions of the structure.
If only selected portions of the structure are in scope, the in scope portions are described in the scoping evaluation.
The associated structure drawings were carefully reviewed to identify the passive, long-lived structures and components, and the identified structures and components were then entered into the license renewal database. Component listings from the SAP database were also reviewed to confirm that all structural components were considered. Plant walkdowns were performed when required for confirmation. Finally, the identified list of passive, long
-lived structures and components was benchmarked against previous license renewal applications.
2.1.5.3.2  Staff Evaluation The staff reviewed the structural screening methodology discussed and documented in LRA Section 2.1.6, the implementing procedures
, and the license renewal drawings. The staff reviewed the applicant's methodology for identifying structural components that are subject to an AMR as required in 10 CFR 54.21(a)(1). The staff verified that the applicant had 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, the Structures Monitoring Program, and scoping and screening reports, which the applicant had used to perform the structural scoping Structures and Components Subject to Aging Management Review 2-32 and screening activities. The staff also reviewed the structural drawings to document the SCs within the scope of license renewal and subject to an AMR. The staff conducted 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 were appropriately implemented and if the screening results were consistent with the CLB requirements. In addition, during the scoping and screening methodology audit, the staff reviewed the turbine building to verify proper implementation of the screening process and performed walkdowns of selected areas.
Based on the review activities, the staff did not identify any discrepancies between the methodology documented and the implementation results.
2.1.5.3.3  Conclusion On the basis of its review of the LRA, implementation procedures, the UFSAR, plant component database, CLB documentation, drawings, specifications and selected scoping and screening reports, discussion with the applicant, and the results of the screening methodology, the staff concludes that the methodology for identification of structural components within the scope of license renewal and subject to an AMR is in accordance with the requirements of the 10 CFR 54.21(a)(1) and, therefore, is acceptable.
2.1.5.4  Electrical Component Screening 2.1.5.4.1  Summary of Technical Information in the Application In LRA Section 2.1.6.1, "Identification of Structures and Components Subject to AMR," the applicant stated:
Screening of electrical and I&C components used a bounding approach as described in NEI 95
-10. Electrical commodity groups were identified without regard to system. Electrical and I&C components/commodity groups are subject to aging management review, unless they are determined to not be in scope at the system level. The commodity groups subject to an AMR are identified by applying the criteria of 10 CFR 54.21(a)(1). This method provides the most efficient means for determining the electrical commodity groups subject to an AMR since many electrical and I&C components/commodity groups are active. The sequence of steps and special considerations for identification of electrical components that require an AMR is as follows:
Electrical and I&C components in within scope systems at Salem were identified and listed. The electrical and I&C component commodity groups were identified from a review of plant documents, controlled drawings, the plant component database (SAP), and interface with the parallel mechanical and civil/structural screening efforts.
Following the identification of the electrical component commodity groups, the criterion of 10 CFR 54.21(a)(1)(i) was applied to identify component commodity groups that perform their functions without moving parts or without a change in configuration or properties (referred to as "passive" Structures and Components Subject to Aging Management Review 2-33 components). These components were identified utilizing the guidance of NEI 95-10 and the EPRI License Renewal Electrical Handbook.
The screening criterion found in 10 CFR 54.21(a)(1)(ii) excludes those components or 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 components and commodity groups that were not previously eliminated by the application of the 10 CFR 54.21(a)(1)(i) screening criterion.
2.1.5.4.2  Staff Evaluation The staff reviewed the applicant's methodology used for electrical screening in LRA Section 2.1.6.1 and subsections, implementing procedures, bases documents, and reports. The staff verified 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 had identified commodity groups which were found to meet the passive criteria in accordance with NEI 95
-10. In addition, the staff determined that the applicant evaluated and identified, passive commodities on whether they were subject to replacement based on a qualified life or specified time period (short
-lived), or not subject to replacement based on a qualified life or specified time period (long
-lived). The applicant had correctly determined the remaining passive, long
-lived components to be subject to an AMR.
The staff reviewed selected portions of the UFSAR, the plant component database, the CLB documentation, documents, procedures, drawings, specifications, and selected scoping and screening reports. The staff conducted detailed discussions with the applicant's license renewal team and reviewed documentation pertinent to the screening process. The staff assessed whether the electrical screening methodology outlined in the LRA and procedures were appropriately implemented and if the scoping results were consistent with CLB requirements. During the scoping and screening methodology audit, the staff discussed the screening methodology with the applicant and reviewed the applicant's screening reports for selected systems to verify proper implementation of the screening process. Based on these audit activities, the staff did not identify any discrepancies between the methodology documented and the implementation results.
2.1.5.4.3  Conclusion On the basis of its review of the LRA, implementing procedures, selected portions of the UFSAR, plant component database, CLB documentation, procedures, drawings, specifications and selected scoping and screening reports, discussion with the applicant, and 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.
 
Structures and Components Subject to Aging Management Review 2-34 2.1.5.5  Screening Methodology Conclusion On the basis of its review of the LRA, implementing procedures, discussions with the applicant's staff, and a selected review of screening results, the staff concludes that the applicant's screening methodology is consistent with the guidance contained in the SRP
-LR and the applicant identified those passive, long
-lived components within the scope of license renewal that are subject to an AMR. The staff concludes that the 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, selected system reviews, and the applicant's response dated May 28, 2010, 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. 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 a n AMR is acceptable.
2.2  Plant-Level Scoping Results
 
====2.2.1 Introduction====
LRA Section 2.1 describes the methodology for identifying systems and structures within the scope of license renewal. In LRA Section 2.2, the applicant used the scoping methodology to determine which systems and structures must be included within the scope of license renewal. The staff reviewed the plant
-level scoping results to determine whether the applicant has properly identified the following three groups:
Systems and structures relied upon to mitigate DBEs, as required by 10 CFR 54.4(a)(1).
Systems and structures the failure of which could prevent satisfactory accomplishment of any safety
-related functions, as required by 10 CFR 54.4(a)(2).
Systems and structures relied on in safety analyses or plant evaluations to perform functions required by regulations referenced in 10 CFR 54.4(a)(3).
2.2.2  Summary of Technical Information in the Application LRA Table 2.2
-1 lists those mechanical systems, electrical and I&C systems, and structures that are within the scope of license renewal. Also in LRA Table 2.2
-1, the applicant listed the systems and structures that do not meet the criteria specified in 10 CFR 54.4(a) and are Structures and Components Subject to Aging Management Review 2-35 excluded from the scope of license renewal.
Based on the DBEs considered in the CLB, other CLB information relating to nonsafety
-related systems and structures, and certain regulated events, the applicant identified plant
-level systems and structures within the scope of license renewal as defined by 10 CFR 54.4. 2.2.3  Staff Evaluati on The purpose of the staff's evaluation was to determine whether the applicant properly identified the systems and structures within the scope of license renewal in accordance with 10 CFR 54.4. 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 provides its evaluation 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 Table 2.2-1 to confirm that there were no omissions of plant-level systems and structures that should be 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 reviewed LRA Section 2.2 and the UFSAR supporting information to determine whether the applicant failed to identify any systems and structures within the scope of license renewal.
 
====2.2.4 Conclusion====
On the basis of its review, as discussed above, 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. 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, thi s Section discusses:
reactor vessel, internals, and reactor coolant system engineered safety features auxiliary systems steam and power conversion systems In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must 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 Structures and Components Subject to Aging Management Review 2-36 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, confirming 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 in SRP
-LR Section 2.3, and took into account where applicable, the system function(s) described in the UFSAR. The objective was to determine whether the applicant has 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 delineated under 10 CFR 54.4(a), the staff verified the applicant properly screened out only:  (1) SCs that have functions performed with moving parts or a change in configuration or properties or (2) SCs that are subject to replacement after a qualified life or specified time period, as described in 10 CFR 54.21(a)(1). For SCs not meeting either of these criteria, the staff verified 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 (if any) include an additional staff evaluation which specifically addresses the applicant's response to the RAI(s) 2.3.1  Reactor Vessel, Internals, and Reactor Coolant System LRA Section 2.3.1 describes the reactor vessel, internals, and reactor coolant system (RCS) 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
:  2.3.1.1  reactor coolant system 2.3.1.2  reactor vessel 2.3.1.3  reactor vessel internals 2.3.1.4  steam generators
 
Structures and Components Subject to Aging Management Review 2-37 2.3.1.1  Reactor Coolant System 2.3.1.1.1  Summary of Technical Information in the Application LRA Section 2.3.1.1 describes the RCS, which is a normally operating system designed to circulate sub
-cooled reactor coolant to transfer heat from the reactor core to the secondary fluid in four (4) steam generators during normal operation, and anticipated operational occurrences. The system is capable of transferring this heat using forced circulation with the reactor coolant pumps during normal operation, or using natural circulation when necessary during emergency operations. The RCS consists of the following plant systems:  the reactor vessel level instrumentation, pressurizer, reactor coolant pressure boundary components (hot leg piping and cold leg piping), reactor coolant pumps and their oil lift system, pressurizer relief tank, pressurizer heaters, pressurizer surge line, pressurizer spray line, and the reactor head vent piping. Reactor vessel level instrumentation consists of two redundant trains of hydraulic components and instrumentation.
LRA Table 2.3.1-1 identifies the components subject to an AMR for the RCS by component type and intended function.
2.3.1.1.2  Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the RCS mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.1.2  Reactor Vessel 2.3.1.2.1  Summary of Technical Information in the Application LRA Section 2.3.1.2 describes the reactor vessel (RV) system.
The RV system is a normally operating system designed to contain the pressure and heat in the core and transfer this heat to the reactor coolant.
The RV consists of the following major components:  reactor vessel, the integrated head assembly, control rod drive mechanisms, the attached vent, flange leak
-off, drain, level instrumentation piping and components, the vessel shells, upper shell flange, nozzle shell course, nozzles, safe ends, closure studs, the lower head, the core support lug, and the primary nozzle supports.
The purpose of the RV system is to maintain the reactor vessel pressure boundary and provide structural support for the reactor vessel internals, core, and control rod drive mechanisms.
The control rod drive system is used to insert negative reactivity into the reactor core. The RV also provides a pressure boundary for fluid in the vessel and acts as a boundary to preclude fission products from entering the environment.
LRA Table 2.3.1-2 identifies the components subject to an AMR for the RV system by component type and intended function.
 
Structures and Components Subject to Aging Management Review 2-38 2.3.1.2.2  Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the RV system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.1.3  Reactor Vessel Internals 2.3.1.3.1  Summary of Technical Information in the Application LRA Section 2.3.1.3 describes the RV internals system.
The RV internals system is a normally operating system designed to maintain the reactor core assembly geometry, to maintain the reactor core subcritical for any mode of operation or DBE, and to introduce negative reactivity to make the reactor subcritical.
The R V internals consist of the upper core support structure, the lower core support structure, and the incore instrumentation support structure.
Also included are the flux thimble tubes, fuel assemblies and the rod cluster control assemblies.
The overall purpose of the RV internals is to direct reactor coolant through the core to achieve acceptable flow distribution and to restrict bypass flow, so that heat transfer performance requirements are met during all modes of operation.
The upper core support structure is used to provide structural support and contain the guide tube assemblies that shield and guide the control rod drive shafts and control rods. The lower core support structure provides structural support for vertical loads, forms a periphery enclosure of the core including core baffles and a bottom flow distribution plate for efficient flow distribution, and provides neutron shielding by means of the thermal shield.
The incore instrumentation support structure is used to provide structural support for the bottom
-mounted incore instrumentation (flux thimbles and thermocouples) and to maintain a pressure boundary between the reactor coolant and the containment atmosphere.
The purpose of the fuel assemblies is to generate heat from the fuel rods, maintain a coolable fuel rod geometry, and promote efficient heat transfer from the nuclear fuel to the reactor coolant. The rod cluster control assemblies are used to provide reactivity control for shutdown, to control reactivity changes resulting from reactor coolant temperature changes, the power coefficient of reactivity, and also void formation.
LRA Table 2.3.1-3 identifies the components subject to an AMR for the reactor vessel internals by component type and intended function. 2.3.1.3.2  Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the RV internals system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
 
Structures and Components Subject to Aging Management Review 2-39 2.3.1.4  Steam Generators 2.3.1.4.1  Summary of Technical Information in the Application LRA Section 2.3.1.4 describes the steam generators. The steam generators are a normally operating system designed to serve as a heat sink for the reactor coolant and to provide a barrier to prevent fission products and activated corrosion products in the reactor coolant from entering the steam system. The steam generators consist of the following plant systems:  steam generators and steam generator drains and blowdown. The major components of the steam generators are the four steam generators per unit. Unit 1 has Westinghouse Model F recirculating steam generators. Unit 2 has AREVA 61/19T recirculating steam generators.
The purpose of the steam generators is to transfer heat from the reactor coolant to the main feedwater via the four recirculating steam generators during normal operation and anticipated operational occurrences so that reactor core thermal limits are not exceeded, to provide a pressure boundary to separate fission products from the environment, and to provide containment isolation.
LRA Table 2.3.1-4 identifies the components subject to an AMR for the steam generators by component type and intended function.
2.3.1.4.2  Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the steam generator system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in
 
10 CFR 54.21(a)(1).
2.3.2  Engineered Safety Features LRA Section 2.3.2 describes the engineered safety features system SCs subject to an AMR for license renewal. The applicant described the supporting SCs of the engineered safety features system in the following LRA sections:
containment spray system  residual heat removal system  safety injection system 2.3.2.1  Containment Spray System 2.3.2.1.1  Summary of Technical Information in the Application LRA Section 2.3.2.1 describes the containment spray system. The containment spray system is a mechanical, standby system designed to reduce containment pressure to nearly atmospheric
 
Structures and Components Subject to Aging Management Review 2-40 pressure, to remove airborne fission products from the containment atmosphere, to minimize corrosion of equipment following a large break loss of coolant accident (LBLOCA), and to limit containment pressure following a main steam
-line break (MSLB) inside the containment structure.
The containment spray system is comprised of two redundant loops.
Each loop consists of one containment spray pump, one eductor, two sets of nozzles, and the necessary piping, valves, instrumentation, and controls.
The purpose of the containment spray system is to remove energy from the environment by transferring heat from the higher temperature atmosphere to the lower temperature spray droplets discharged from the containment spray nozzles.
LRA Table 2.3.2-1 identifies the components subject to an AMR for containment spray system by component type and intended function.
2.3.2.1.2  Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the containment spray system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.2.2  Residual Heat Removal System 2.3.2.2.1  Summary of Technical Information in the Application LRA Section 2.3.2.2 describes the residual heat removal system. The residual heat removal system is a standby, mechanical emergency core cooling system (ECCS) designed to provide low pressure injection flow and long
-term core cooling following a DBE. The residual heat removal system is comprised of two residual heat removal pumps, two residual heat removal heat exchangers, one letdown booster pump, the containment sump and the associated piping, valves, instrumentation, and controls.
The residual heat removal system's purpose is to remove decay heat from the core and residual heat from the RCS during the latter stages of a plant cooldown, maintain the reactor coolant temperature during refueling, and provide a means for filling and draining the reactor cavity and fuel transfer canal during refueling. In the event of a loss of coolant accident (LOCA), the system injects borated water into the reactor vessel.
LRA Table 2.3.2-2 identifies the components subject to an AMR for the residual heat removal system by component type and intended function.
2.3.2.2.2  Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the residual heat removal system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
 
Structures and Components Subject to Aging Management Review 2-41 2.3.2.3  Safety Injection System 2.3.2.3.1  Summary of Technical Information in the Application LRA Section 2.3.2.3 describes the safety injection system.
The safety injection system is a standby, intermediate
-pressure emergency core cooling system (ECCS) designed to provide emergency core cooling following a LOCA or main steam
-line break (MSLB) in the containment structure.
The safety injection system is one part of the ECCS along with the residual heat removal system and chemical & volume control system.
The ECCS consists of the following components:  centrifugal charging pumps, residual heat removal pumps, safety injection pumps, safety injection accumulators, boron injection tank, refueling water storage tank, and the necessary piping, valves, controls and instrumentation.
The safety injection system's purpose is to provide core cooling by injecting borated water from the refueling water storage tank into the core following a LOCA or MSLB, provide core reflooding during a LBLOCA by injecting borated water from the safety injection accumulators, and provide containment isolation for piping penetrations following a DBE.
LRA Table 2.3.2-3 identifies the components subject to an AMR for the safety injection system by component type and intended function.
2.3.2.3.2  Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the safety injection system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3  Auxiliary Systems LRA Section 2.3.3 identifies the auxiliary systems SCs subject to an AMR for license renewal.
The applicant described the supporting SCs of the auxiliary systems in the following LRA sections:  2.3.3.1 auxiliary building ventilation system 2.3.3.2 chemical and volume control system 2.3.3.3 chilled water system 2.3.3.4 circulating water system 2.3.3.5 component cooling system 2.3.3.6 compressed air system 2.3.3.7 containment ventilation system 2.3.3.8 control area ventilation system 2.3.3.9 cranes and hoists  2.3.3.10 demineralized water system 2.3.3.11 emergency diesel generators and auxiliary systems 2.3.3.12 fire protection system 2.3.3.13 fresh water system
 
Structures and Components Subject to Aging Management Review 2-42  2.3.3.14 fuel handling and fuel storage system 2.3.3.15 fuel handling ventilation system 2.3.3.16 fuel oil system 2.3.3.17 heating water & heating steam 2.3.3.18 non-radioactive drain system 2.3.3.19 radiation monitoring system 2.3.3.20 radioactive drain system 2.3.3.21 radwaste system 2.3.3.22 sampling system 2.3.3.23 service water system 2.3.3.24 service water ventilation system 2.3.3.25 spent fuel cooling system 2.3.3.26 switchgear and penetration area ventilation system Auxiliary Systems Generic Requests for Additional Information On April 14, 2010, the staff, in RAI 2.3-01, requested that the applicant provide information enabling the staff to locate the missing continuation drawings and explain some inconsistencies in the license renewal drawings. On May 12, 2010, the applicant provided the necessary drawing and explanations of the inconsistencies.
Based on its review, the staff finds the applicant's response to RAI 2.3-01 acceptable because the applicant provided the continuation locations or a description, including component types, to the license renewal boundary. Therefore, the staff's concern described in RAI 2.3-01 is resolved. 2.3.3.1  Auxiliary Building Ventilation System 2.3.3.1.1  Summary of Technical Information in the Application LRA Section 2.3.3.1 describes the auxiliary building ventilation system. The auxiliary building ventilation system is a mechanical, normally operating, once
-through heating and ventilating system for each Unit designed for long
-term continuous operation during normal and emergency modes of plant operation.
The purpose of the auxiliary building ventilation system is to control air temperature, air cleanliness, and maintain a negative pressure within selected areas in the auxiliary building during normal and emergency modes of plant operation.
LRA Table 2.3.3-1 identifies the components subject to an AMR for the auxiliary building ventilation system by component type and intended function.
2.3.3.1.2  Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the auxiliary building ventilation system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
 
Structures and Components Subject to Aging Management Review 2-43 2.3.3.2  Chemical and Volume Control System 2.3.3.2.1  Summary of Technical Information in the Application LRA Section 2.3.3.2 describes the chemical and volume control (CVC) system which consists of the following plant systems:  (1) CVC system, (2) boric acid recovery system, and (3) primary water recovery system. The CVC system is a normally operating mechanical system designed to control the inventory of the RCS during all phases of normal reactor operation.
The main purposes of the CVC system are the followings:  (1) inject borated water from the refueling water storage tank into the reactor core following a LOCA for emergency cooling, (2) control the boric acid concentration in the reactor coolant for reactivity management, (3) control the reactor coolant inventory during all phases of reactor operations including hydrostatic testing of the RCS, (4) provide for purification of the reactor coolant to remove corrosion and fission products, (5) provide makeup to the refueling water storage tank and spent fuel pool, (6) provides seal injection water for the reactor coolant pump seals, and (7) vent gases from the RCS.
LRA Table 2.3.3-2 identifies the components subject to an AMR for the CVC system by component type and intended function.
2.3.3.2.2  Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the CVC system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.3  Chilled Water System 2.3.3.3.1  Summary of Technical Information in the Application LRA Section 2.3.3.3 describes the chilled water system which consists of the following plant systems:  (1) auxiliary building, (2) administration building, (3) clean facilities building, (4) controlled facilities building, (5) secondary chemistry laboratory, and (6) service building. The chilled water system is a normally operating, mechanical system designed to provide cooling to safety
-related and nonsafety
-related ventilation systems.
The purpose of the chilled water system is to provide cooling water to the control room ventilation coils, nonsafety
-related areas and sampling heat exchangers.
LRA Table 2.3.3-3 identifies the components subject to an AMR for the chilled water system by component type and intended function.
2.3.3.3.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.3, UFSAR Sections 9.4.1.2 and 9.3.1.2, and the license renewal boundary drawings using the evaluation methodology described in SER Section 2.3.
Structures and Components Subject to Aging Management Review 2-44 The staff's review identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results.
In RAI 2.3.3.3-01, dated April 14, 2010, the staff noted that Unit 1 drawing LR
-205216 (SH1) at three locations shows a change of scope classification from 10 CF R 54.4(a)(1) to 10 CFR 54.4(a)(2) after the 1/8 inch diameter orifices near valves 1CH28, 1CH6 and 1CH20. The piping class break is shown downstream of the 1/8 inch diameter orifices. The inclusion of safety-related piping within scope for 10 CFR 54.4(a)(2) would conflict with the scoping procedure described in LRA Section 2.1.5.1. The applicant was requested to provide additional information to clarify these scoping classifications.
In its response dated May 12, 2010, the applicant stated that the piping on the downstream side of the 1/8
-inch restricting orifices through the drain lines, including the automatic vacuum relief valves, are within the scope of license renewal under 10 CFR 54.4(a)(2).
The license renewal scoping boundary is shown correctly as described on LR
-205216 (SH1).
The restricting orifices provide adequate isolation of the safety
-related chilled water system equipment from the nonsafety-related drain system.
The drain lines on the downstream side of the restricting orifices are not required to perform any 10 CFR 54.4(a)(1) function and are, therefore, not in the scope of license renewal under 10 CFR 54.4(a)(1).
The drawing is revised to show the piping classification break at the outlet of the orifice.
The drain lines on the downstream side of the restricting orifices contain water and, therefore, are in the scope of license renewal under 10 CFR 54.4(a)(2) for potential spatial interaction.
Based on its review, the staff finds the applicant's response to RAI 2.3.3.3-01 acceptable because the applicant clarified the scoping classification of the pipe lines in question. The staff agrees that the restricting orifices provide adequate isolation of the safety
-related chilled water system equipment from the nonsafety
-related drain system and the drain lines on the downstream side of the restricting orifices contain water and, therefore, are in the scope o f license renewal under 10 CFR 54.4(a)(2) for potential spatial interaction with safety
-related components
. Therefore, the staff's concern described in RAI 2.3.3.3-01 is resolved.
In RAI 2.3.3.3-02 dated April 14, 2010, the staff noted that Unit 2 drawing LR-205216 (SH2), at three locations show a change of scope classification from 10 CFR 54.4(a)(1) to 10 CFR 54.4(a)(2) after the 1/8 inch diameter orifices near valves 2CH28, 2CH20 and 2CH6. The piping class break is shown downstream of the 1/8 inch diameter orifices. The inclusion of safety-related piping in scope for 10 CFR 54.4(a)(2) would conflict with the scoping procedure described in LRA Section 2.1.5.1. The applicant was requested to provide additional information to clarify these scoping classifications.
In its response dated May 12, 2010, the applicant stated that the piping on the downstream side of the 1/8
-inch restricting orifices through the drain lines, including the automatic vacuum relief valves, are shown as red and in the scope of license renewal under 10 CFR 54.4(a)(2). The license renewal scoping boundary is shown correctly as described above on LR
-205216 (SH2). The restricting orifices provide adequate isolation of the safety
-related Chilled Water System equipment from the nonsafety
-related drain system. The drain lines on the downstream side of the restricting orifices are not required to perform any 10 CFR 54.4(a)(1) function and are, therefore, not in the scope of license renewal under 10 CFR 54.4(a)(1). The drawing is revised to show the piping classification break at the outlet of the orifice. The drain lines on the downstream side of the restricting orifices contain water and, therefore, are in the scope of license renewal under 10 CFR 54.4(a)(2) for potential spatial interaction.
 
Structures and Components Subject to Aging Management Review 2-45 Based on its review, the staff finds the applicant's response to RAI 2.3.3.3-02 acceptable because the applicant clarified the scoping classification of the pipe lines in question. The staff agrees that the restricting orifices provide adequate isolation of the safety
-related chilled water system equipment from the nonsafety
-related drain system and the drain lines on the downstream side of the restricting orifices contain water and, therefore, are in the scope of license renewal under 10 CFR 54.4(a)(2) for potential spatial interaction with safety
-related components. Therefore, the staff's concern described in RAI 2.3.3.3-02 is resolved.
In RAI 2.3.3.3-03, dated April 14, 2010, the staff noted drawing LR
-205216 (SH 1) show ed lines 2"-1CH1143 and 2"
-1CH1142 out of the No.
1 expansion tank (1CHE1) as in scope for license renewal for 10 CFR 54.4(a)(1) whereas similar lines 2"
-2CH1105 and 2"
-2CH110 out of the No. 2 expansion tank (2CHE8) on license renewal drawing LR
-205216 (SH2) are shown within scope for 10 CFR 54.4(a)(2)The applicant was requested to provide additional information explaining why there is a difference in scope classification in similar lines.
In its response dated May 12, 2010, the applicant stated that there are two level indicators on the No. 1 expansion tank.
One level indicator within the scope of license renewal under 10 CFR 54.4(a)(1) and the other level indicator is within the scope of license renewal under 10 CFR 54.4(a)(2).
On the Unit 1 license renewal boundary drawing LR
-205216 (SH1), location D/E-7, the first set of piping lines (2"- 1CH1 143 and 2"-1CH1 142) for level indicator, LA4156/LC4156, are shown correctly as green in scope for license renewal under 10 CFR 54.4 (a)(1). However, the Unit 1 license renewal boundary drawing LR
-205216 (SH1), location D/E
-6, incorrectly shows the second set of piping lines for level indicator, LL6229, as green and in the scope of license renewal under 10 CFR 54.4(a)(1)
The drawing is revised to show the piping lines (2"-1CH1150, 2"-1CH1151, and 1/4"-1CH1156) and components on the downstream side of the root valves to the No. 1 chilled water expansion tank level indicator, LL6229, as red and in the scope under 10 CFR 54.4(a)(2) for potential spatial interaction because the piping contains water and is located in the auxiliary building inner penetration area, which contains safety
-related components.
Therefore, the piping and components beyond the root valves to the chilled water expansion tank level indicator, LL6229, should show as red and in the scope of license renewal under 10 CFR 54.4(a)(2) for potential spatial interaction.
The Unit 1 piping lines (2"-1 CH1 149 and 2"-1 CH1 148), location D/E
-6, up to and including the root valves (valves number 1 CH153 and 1 CHi154) for the No. 1 chilled water expansion tank level indicator (LL6229), provide a pressure boundary for the safety
-related chilled water system and are in the scope of license renewal under 10 CFR 54.4(a)(1), and are shown correctly as green on this license renewal boundary drawing.
The Unit 2 license renewal boundary drawing, L R-205216 (SH2), location D/E
-3, correctly shows the corresponding piping lines (2"-2CH1 105 and 2"-2CH1 10[7]) and components for the No. 2 chiller expansion tank level indicators and are 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 2.3.3.3-03 acceptable because the applicant identified and corrected the scoping classification of the piping lines. The staff agrees with the applicant's classification of Unit 2 piping lines and components for No. 2 chiller expansion tank level indicator s and Unit 1 piping and components on the downstream side of the root valves to the No. 1 chilled water expansion tank level indicator, LL6229, within the scope of license renewal under 10 CFR 54.4(a)(2) because of the potential spatial interaction with safety
-related components. The staff also agrees with the applicant's classification of Unit 1, location D/E-7, the first set of piping lines for level indicator, Structures and Components Subject to Aging Management Review 2-46 LA4156/LC4156, and the piping lines for location D/E
-6, up to and including the root valves for the No. 1 chilled water expansion tank level indicator because it provide s a pressure boundary for the safety
-related chilled water system and are in the scope of license renewal under 10 CFR 54.4(a)(1)
. Therefore, the staff's concern described in RAI 2.3.3.3-03 is resolved.
2.3.3.3.3  Conclusion The staff reviewed the LRA, UFSAR, RAI responses, and boundary drawings to determine whether the applicant failed to identify any components within the scope of license renewal. In addition, the staff's review determined whether the applicant failed to identify any components subject to an AMR. On the basis of its review, the staff concludes the applicant has appropriately identified the chilled water system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the chilled water system mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.4  Circulating Water System 2.3.3.4.1  Summary of Technical Information in the Application LRA Section 2.3.3.4 describes the circulating water system which consists of the following plant systems:  the service water system and the non
-radioactive liquid waste system. The circulating water system is a normally operating system designed to supply Delaware River water to cool each unit's triple
-shell main condenser, discharging the effluent back to the Delaware River at a sufficient distance offshore to minimize thermal recirculation and promote rapid mixing with the river water.
LRA Table 2.3.3-4 identifies the components subject to an AMR for the circulating water system by component type and intended function.
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 applicable boundary drawings, the staff concludes that the applicant has appropriately identified the circulating water system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.5  Component Cooling System 2.3.3.5.1  Summary of Technical Information in the Application LRA Section 2.3.3.5 describes the component cooling (CC) system. The CC system is a normally operating, mechanical system designed to provide heat removal from safeguards equipment associated with heat removal from the RCS during all phases of normal reactor operation. In the event of a LOCA, the system has an emergency core cooling system (ECCS) function to reduce reactor coolant system temperature through the residual heat removal heat exchangers for long
-term core cooling. The heat is then transferred from the CC system to the Structures and Components Subject to Aging Management Review 2-47 service water system. The CC system is also designed to provide intermediate loop cooling for safety-related and nonsafety
-related plant loads.
The component cooling system accomplishes this purpose by circulating chromated cooling water through the safety
-related heat exchangers, the ECCS pump mechanical seal coolers, and nonsafety-related plant heat exchangers and coolers.
LRA Table 2.3.3-5 identifies the components subject to an AMR for the CC system by component type and intended function.
2.3.3.5.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.5, UFSAR Section 9.2.2, 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 necessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.
In RAI 2.3.3.5-01, dated April 14, 2010, the staff noted anchors for nonsafety
-related piping connected to safety
-related piping on four drawings (sixteen locations) could not be located.
The staff could not verify that the (a)(2) scoping boundary extended out to the first anchor on the nonsafety line, as described in the applicant's scoping methodology for spatial interaction.
Therefore the staff requested that the applicant provide additional information to locate an anchor on the pipe lines between the safety
-nonsafety interface and the end of the (a)(2) scoping boundary.
The applicant's response, dated May 12, 2010, described the location of the anchors, which are within the existing (a)(2) scoping boundary.
This conforms with the applicant's methodology and did not result in the inclusion of any additional components within the scope of license renewal. Based upon its review, the staff finds the applicant's response to RAI 2.3.3.5-01 acceptable
. In RAI 2.3.3.5-02, dated April 14, 2010, the staff noted on drawing LR
-205229 (SH1) a Section of pneumatic piping (1063 B
-N) within scope for 10 CFR 54.4(a)(2) that continues to drawing LR
-205231 (SH2) and LR
-205315 (SH1).
The continuation on drawing LR
-205231 (SH2) is not within scope. The applicant was requested to clarify the scoping classification of the pneumatic piping section.
In its response dated May 12, 2010, the applicant stated that the boundary drawing incorrectly shows the pneumatic tubing as within the scope of license renewal under 10 CFR 54.4(a)(2). The pneumatic tubing is not within the scope of license renewal because it does not have the potential for spatial interaction with safety
-related components
, does not contain high energy fluids or provide structural support to safety
-related components.
The pneumatic tubing provides pneumatic supply air to the air
-operated valve on the downstream side of the boric acid evaporator condenser. The drawing has been revised to reflect that this pneumatic tubing is not within scope.
Based on its review, the staff finds the applicant's response to RAI 2.3.3.5-02 acceptable because the pneumatic tubing does not contain high energy fluids, does not provide structural support to safety
-related components, and does not have the potential for spatial interation with safet y-related components.
The staff agrees with the applicant that the pneumatic tubing is not Structures and Components Subject to Aging Management Review 2-48 within the scope of license renewal. Therefore, the staff's concern described in RAI 2.3.3.5-02 is resolved.
2.3.3.5.3  Conclusion The staff reviewed the LRA, UFSAR, RAI responses, and boundary drawings to determin e whether the applicant failed to identify any components within the scope of license renewal. In addition, the staff's review determined whether the applicant failed to identify any components subject to an AMR. On the basis of its review, the staff concludes the applicant has appropriately identified the component cooling system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the CC system mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.6  Compressed Air System 2.3.3.6.1  Summary of Technical Information in the Application LRA Section 2.3.3.6 describes the compressed air system which consists of the following plant systems:  the station air system and the control air system. The compressed air system is a normally operating mechanical system that provides motive power for safety
-related and nonsafety-related instrumentation, controls and equipment. The compressed air system also provides compressed air to service air connections throughout the plant, including providing a constant flow of penetration cooling air to hot pipe containment penetrations.
The purpose of the compressed air system is to provide a continuous supply of compressed air at the appropriate pressure, temperature, flow rate , and air quality to support pneumatic instrumentation and controls, air
-operated plant and service equipment, and penetration cooling requirements for both units of Salem. The compressed air system must supply critical air users with redundant air sources such that the loss of an air header, compressor or other single failure will not result in the need to shut down the plant or compromise its operation. LRA Table 2.3.3-6 identifies the components subject to an AMR for the compressed air system by component type and intended function.
2.3.3.6.2  Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the compressed 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 the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.7  Containment Ventilation System 2.3.3.7.1  Summary of Technical Information in the Application LRA Section 2.3.3.7 describes the containment ventilation (CV) system which consists of the following plant systems:  containment fan cooler system, reactor nozzle support ventilation Structures and Components Subject to Aging Management Review 2-49 system, reactor shield ventilation system, pressure
-vacuum relief system, containment purge system, hydrogen recombiner system, containment iodine removal system, and control rod drive ventilation system.
The CV system is a normally operating mechanical system designed to provide heat removal from containment during normal operations and DBEs. The purpose of the CV system is to provide air circulation and heat removal from the containment atmosphere to prevent overheating.
The CV system accomplishes this purpose by using fans to circulate the containment air through coolers supplied with cooling water by the service water system and to force air through the reactor shield and nozzle support areas. Another purpose of the CV system is to provide isolation capability to maintain the integrity of the containment barrier.
The CV system accomplishes this purpose by blank flanges or by automatic valves that close when required for containment isolation.
LRA Table 2.3.3-7 identifies the components subject to an AMR for the CV system by component type and intended function.
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 applicable boundary drawings, the staff concludes that the applicant has appropriately identified the CV system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.8  Control Area Ventilation System 2.3.3.8.1  Summary of Technical Information in the Application LRA Section 2.3.3.8 describes the control area ventilation (CAV) system which consists of the following plant systems:  the control area air conditioning system and the control room emergency air conditioning system. The CAV system is a normally operating mechanical system designed to maintain room temperatures, humidity and habitability of the control room envelope and control room areas under normal and design bases accident conditions.
The purposes of the CAV system are to provide clean, filtered air at satisfactory temperature and humidity to the control room envelope and the control room area and to ensure uninterrupted safe occupancy of the control room envelope under emergency conditions by filtering airborne radioactive particles and maintaining the control room envelope at a positive differential pressure.
LRA Table 2.3.3-8 identifies the components subject to an AMR for the CAV system by component type and intended function.
2.3.3.8.2  Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the CAV system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the Structures and Components Subject to Aging Management Review 2-50 system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.9  Cranes and Hoists 2.3.3.9.1  Summary of Technical Information in the Application LRA Section 2.3.3.9 describes the cranes and hoists (CH) system which consists of load handling overhead bridge cranes, monorails, jib cranes, lifting devices, and hoists provided throughout the facility to support operation and maintenance activities. Major cranes include the polar gantry crane, cask
-handling crane, main turbine area gantry crane and aux turbine area crane, solid radwaste overhead crane, 90T grove crane and 900 series American crawler crane. The polar gantry crane services the operating floor and is used to lift heavy loads such as the reactor vessel integrated head, and upper and lower reactor vessel internals The purpose of the CH system is to safely move material and equipment as required to support operations and maintenance activities.
LRA Table 2.3.3-9 identifies the components subject to an AMR for the CH system by component type and intended function.
2.3.3.9.2  Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the CH system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.10  Demineralized Water System 2.3.3.10.1 Summary of Technical Information in the Application LRA Section 2.3.3.10 describes the demineralized water (DW) system which consists of the following plant systems:  demineralized water make
-up system and demineralized water-restricted areas system. The DW system is a normally operating system designed to purify both well water and recovered water from the condensers to high purity water standards for various uses.
The purpose of the DW system is to provide a source of demineralized water for various vital and non-vital uses, such as providing an alternate supply of demineralized water to the auxiliary feedwater system, providing make
-up to the primary water storage tank, boric acid batching tanks, component cooling water surge tanks, chilled water expansion tanks, emergency diesel generator jacket water expansion tanks, stator cooling, spent fuel pool and the main condenser. It also provides a source of flushing water to the safety injection, residual heat removal, condensate polisher, and the steam generators. Portions of the DW system are also credited for post-fire safe shutdown.
 
Structures and Components Subject to Aging Management Review 2-51 LRA Table 2.3.3-10 identifies the components subject to an AMR for the DW system by component type and intended function.
2.3.3.10.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the DW system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.11  Emergency Diesel Generator and Auxiliaries System 2.3.3.11.1 Summary of Technical Information in the Application LRA Section 2.3.3.11 describes the emergency diesel generator and auxiliaries (EDGA) system. The EDGA system is a standby mechanical system designed to supply electrical power to key plant components when normal offsite power sources are not available.
The purpose of the EDGA system is to provide electrical power for engineered safety features when normal offsite power is not available. Any two of the three diesel generators and their associated vital busses can supply sufficient power for operation of the required safeguards equipment for a design basis LOCA coincident with a loss of offsite power.
LRA Table 2.3.3-11 identifies the components subject to an AMR for the EDGA system by component type and intended function.
2.3.3.11.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the EDGA system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.12  Fire Protection System 2.3.3.12.1 Summary of Technical Information in the Application LRA Section 2.3.3.12 describes the fire protection system which consists of the following plant systems:  fire protection water systems, carbon dioxide (CO 2) systems, halon system, foam system, portable fire extinguishers, and fire detection and alarm systems. Fire protection system also includes fire barrier, penetrations seals, and fire wrap for cable trays. The fire protection system is a normally operating mechanical system, designed for the rapid detection and suppression of a fire at the plant.
The purpose of the fire protection system is to prevent fires from starting, promptly detect and suppress fires to limit damage, and
, in the event of a fire , allow for safe shutdown of the reactor Structures and Components Subject to Aging Management Review 2-52 to occur.
The fire protection system accomplishes this purpose by providing fire protection equipment in the form of detectors, alarms, fire barriers and suppression systems for selected areas of the plant. In addition, the fire protection system provides a backup source of water to the auxiliary feedwater system in the event of loss of the auxiliary feedwater storage tanks.
The Salem's fire protection water system is physically connected to the Hope Creek Generating Station fire water system by the use of sectionalizing valves. The two systems are normally isolated from each other.
LRA Table 2.3.3-12 identifies the components subject to an AMR for the fire protection system by component type and intended function. 2.3.3.12.2 Staff Evaluation The staff reviewed Salem Units 1 and 2 LRA; LRA drawings; Section 9.5.1.1, "Fire Protection Program," of the UFSAR for Salem Units 1 and 2; and the following fire protection CLB documents listed in Salem Unit 1, Operating License Condition 2.C(5) and in Salem Unit 2, Operating License Condition 2.C(10):  Amendment No.
21 to Facility Operating License No. DPR-70, dated November 20, 1979, and safety evaluation reports dated September 16, 1982, November 5, 1982, June 17, 1983, July 20, 1989, November 14, 1990, June 17, 1994, and January 7, 2004. 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).
The staff's review of LRA, Section 2.3.3.12, identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.
In RAI 2.3.3.12-1 of its letter dated March 22, 2010, the staff stated that LRA drawing LR-205221 SH.1 showed the following fire protection system components as out of scope (i.e., not colored in green):  Productions Wells Nos.
1, 2, 3, 5, and 6 in the Fresh Water Well Pump House; Fire Pump House; Tank 1FWE4 and associated components to the Fire Pump House and to the Fire Protection Storage Tank 1FWE16 The staff requested that the applicant verify whether the fire protection systems and components listed above ar e within the scope of license renewal in accordance with 10 CFR 54.4(a) and whether they are subject to an AMR in accordance with 10 CFR 54.21(a)(1) or provide justification for the exclusion if these systems and components are not subject to an AMR. In a letter dated April 19, 2010, the applicant responded to RAI 2.3.3.12-1 and stated:
License renewal drawing LR
-205222, Sheet 4, "Fire Protection," shows the No.
1 and No. 2 fresh water and fire protection water storage tanks. Each tank has a capacity of 350,000 gallons, with 300,000 gallons reserved for fire protection use and 50,000 gallons available for domestic service. The reserved capacity in Structures and Components Subject to Aging Management Review 2-53 each tank is sufficient to supply the greatest system demand plus an additional 1000 GPM for hose streams for a minimum of two hours, representing 100%
redundant capacity. These two independent tanks supply water to the two fire pumps (1FPE12, 2FPE12) and jockey pump (1FPE11). The fire pump suction piping and valve arrangement allows either fire pump to take water from either or both water storage tanks.
The fresh water and fire protection water storage tanks are also shown on license renewal drawing LR
-205221, Sheet 1, "Fresh Water."
The fresh water system uses the 50,000 gallons available in each tank that is not reserved for fire protection. The production wells (Nos.
1, 2, 3,5, and 6) in the fresh water well pump house are included in the fresh water system as described in LRA Section 2.3.3.13, and are not part of the fire protection system. Similarly, the 15,000 gallon fresh water tank (1FWE4), fresh water pumps, pressure booster pumps, fresh water supply chlorination tank and associated piping and components up to, but not including the fresh water and fire protection water storage tanks 1FWE16 and 1FWE18, are part of the fresh water system.
The fresh water system is a nonsafety
-related, normally operating mechanical system designed to provide a source of water for potable, sanitary, and process make-up use. The system also provides makeup water from the production wells to the fresh water and fire protection water storage tanks, which are part of the fire protection system. Water level in each tank is maintained above the minimum required to assure a reserve volume of 300,000 gallons for fire protection. The reserve volume in each tank is adequate to meet fire protection system demands in the event of a fire, without the need for tank makeup. The fresh water system production well pumps and associated piping and components are not required to support any fire protection intended functions for license renewal. The fresh water system piping and components shown in black on drawing
 
LR-205221, Sheet 1 do not provide structural support for safety
-related components, and do not have the potential for spatial interaction because they are not located in the vicinity of safety
-related components. Therefore, the production wells (Nos.
1, 2, 3, 5, and 6) in the fresh water well pump house, the 15,000 gallon fresh water tank (1FWE4), and the associated piping and components in the fresh water system shown in black on drawing LR
-205221, Sheet 1 are not witihin the scope of license renewal and are not subject to AMR.
The fire pump house structure is within the scope of license renewal, and is addressed in the LRA Sections 2.4.4 and 2.4.17 for structures.
The staff reviewed the applicant response to RAI 2.3.3.12-1. The staff verified that production wells Nos.
1, 2, 3, 5, and 6, and  tank 1FWE4 and associated components to the fire pump house and to the fire protection storage tank 1FWE16 are part of the fresh water system. Further, the staff found that, since the fresh water system does not have any intended functions Structures and Components Subject to Aging Management Review 2-54 that satisfy any of the criteria in 10 CFR 54.4(a), the fresh water system and its components (e.g., productions wells Nos.
1, 2, 3, 5, and 6, tank 1FWE4 and associated components to the fire pump house and to the fire protection storage tank 1FWE16) are not within the scope of license renewal and are not subject to an AMR. Based on its review, the staff finds the applicant response to this portion of RAI 2.3.3.12-1 acceptable for the purpose of determining whether the applicant has adequately identified the fire protection system components within the scope of license renewal.
The staff also reviewed the applicant response to RAI 2.3.3.12-1 in regard to the fire pump house. The staff verified that the fire pump house is within the scope of license renewal as stated in LRA Sections 2.4.4 and 2.4.17. Based on its review, the staff finds the applicant response to RAI 2.3.3.12-1 in regard to the fire pump house acceptable for the purpose of determining whether the applicant has adequately identified the fire protection system components within the scope of license renewal.
In RAI 2.3.3.12-2 of its letter dated March 22, 2010, the staff stated that Tabl es 2.3.3.12 and 3.3.2-12 of the LRA do not include the following fire protection components:  hose racks, pipe supports, couplings, and tubing, filter housing, flame arrestor, passive components in diesel engines for fire water pumps, fire retardant coating for structural steel, and fire retardant coating on duct work.
The staff requested that the applicant verify whether the fire protection components listed above are within the scope of license renewal in accordance with 10 CFR 54.4(a) and whether they are subject to an AMR in accordance with 10 CFR 54.21(a)(1). The staff further requested that, if these components are excluded from the scope of license renewal and are not subject to an AMR, the applicant provide justification for the exclusion.
In a letter dated April 19, 2010, the applicant responded to RAI 2.3.3.12-2 and stated:
The scoping results of each of the fire protection components are as follows:
Hose Racks
:  Hose rack assemblies consist of valves, piping and fittings. These components are in the scope of license renewal and subject to AMR. They are included in the "Valve Body" and "Piping and Fittings" component types in LRA Tables 2.3.3-12 and 3.3.2-12. Fire hoses associated with hose racks are evaluated as consumables as described in LRA Section 2.1.6.4. Fire hoses are periodically inspected in accordance with NFPA standards and replaced as required. Therefore, fire hoses are not considered long
-lived and are not subject to an AMRfire hoses are not considered long-lived and are not subject to an AMR Filter Housing
:  Filter housings are included in the component category of Strainer Body in LRA Tables 2.3.3-12 and 3.3.2
-12 and, therefore, are within the scope of license renewal and are subject to an AMR. Flame Arrestor
:  Flame arrestors exist on each of the six Diesel Fuel Oil Day Tanks and on each of the two Fire Pump Day Tanks. They are shown on Boundary Drawings 205249, Sheets 2 and 3. These flame arrestors are evaluated with the fuel oil system. LRA Tables 2.3.3-16 and 3.3.2
-16 include flame arrestors as a component type.
Structures and Components Subject to Aging Management Review 2-55 Therefore, flame arrestors are within the scope of license renewal and are subject to an AMR. Passive components in diesel engines for fire water pumps
:  The diesel
-driven fire water pumps were purchased as a pump and pump driver assembly from the pump manufacturer. The pump and diesel engine driver are mounted together on the vendor
-supplied equipment base plate, which is anchored and grouted to the fire pump house foundation slab. The equipment supports and supporting structural components are subject to an AMR and are included in the applicable tables in LRA Sections 2.4.4 and 3.5
. The diesel engines as supplied from the manufacturer include various components necessary to support engine operation. Many of these components are either internal to the engine, or are physically mounted on the engine. These components are considered integral subcomponent parts of the active diesel engine assembly. Table 2.1-5 of NUREG
-1800, Revision 1, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants" and Appendix B of NEI 95-10, Revision 6, "Industry Guideline for Implementing the Requirements of 10 CFR Part 54 - The License Renewal Rule" indicate that Fire Pump Diesel Engines are not subject to an AMR. The engine components that are part of the active engine assembly are not included in LRA Tables 2.3.3-12 or 3.3.2-12. LR-205249 boundary drawing, Sheet 3, Note 7 indicates that the diesel engine is an active assembly and not subject to an AMR. Fuel oil components that are not part of the active diesel engine assembly are evaluated with the fuel oil system and are included in LRA Tables 2.3.3-16 and 3.3.2-16. This includes the fuel oil storage tank and the fuel inlet and return piping and components from the tank up to the diesel engine assembly. The component types are Tanks, Piping and Fittings, and Valve Body.
Fire retardant coating for structural steel
:  There is no fire retardant coating on structural steel at Salem. Therefore, this coating is not included in Tables 2.3.3-12 and 3.3.2
-12. Fire retardant coating is not in the scope of license renewal and is not subject to AMR.
Fire retardant coating on duct work
:  Fire retardant coating on duct work is included in the component category Fire Barriers (Wraps) in LRA Tables 2.3.3-12 and 3.3.2-12 and is within the scope of license renewal and is subject to an AMR. The staff reviewed the applicant response to RAI 2.3.3.12-2. The staff verified that the following components are addressed in the LRA, that they are within the scope of license renewal and subject to an AMR:  hose racks are addressed under the component categories of valve body/piping and fittings in LRA Tables 2.3.3-12 and 3.3.2
-12; filter housings are addressed under the component category Strainer Body in LRA Tables 2.3.3-12 and 3.3.2
-12; flame arrestor are addressed as part of the fuel oil system in LRA Tables 2.3.3-16 and 3.3.2
-16; and fire retardant coating on duct work is addressed under the component category Fire Barriers in Structures and Components Subject to Aging Management Review 2-56 LRA Tables 2.3.3-12 and 3.3.2
-12. Based on its review, the staff concludes that hose racks, filter housings, flame arrestor, and fire retardant coating on duct work are included within the scope of license renewal and are subject to an AMR. The staff found the applicant response to this portion of RAI 2.3.3.12-2 acceptable.
The staff also reviewed the applicant response to RAI 2.3.3.12-2 in regard to passive components in diesel engines for fire water pumps. The applicant stated that the passive components in diesel engines for fire water pumps are evaluated with the fuel oil system in LRA Tables 2.3.3-16 and 3.3.2
-16 under the passive component types of Tanks, Piping and Fittings, and Valve Body. These passive components include the fuel oil storage tank, the fuel inlet and return piping and components from the tank up to the diesel engine assembly. The staff reviewed the applicant response and verified that the passive components in diesel engines for fire water pumps listed by the applicant are included in LRA Tables 2.3.3-16 and 3.3.2
-16, that they are included within the scope of license renewal and are subject to an AMR. The staff found the applicant response to this portion of RAI 2.3.3.12-2 acceptable. The staff agrees with the applicant that the active components that are part of the diesel engine assembly are not
 
within the scope of license renewal and are not subject to an AMR. Based on its review, the staff found the applicant response to this portion of RAI 2.3.3.12-2 acceptable.
Finally, in regard to fire retardant coating on structural steel, the applicant stated that there is no fire retardant coating on structural steel at Salem and that, therefore, fire retardant coating on structural steel is not included in Tables 2.3.3-12 and 3.3.2
-12. Based the applicant's statement that there is no fire retardant coating on structural steel, the staff found the applicant response to this portion of RAI 2.3.3.12-2 acceptable.
Based on its review the staff found that the applicant had addressed and resolved each item in response to RAI as discussed above. Therefore, the staff found response to the RAI 2.3.3.12-2 acceptable for the purpose of determining whether the applicant has adequately identified the fire protection system components within the scope of license renewal.
In RAI 2.3.3.12-3 of its letter dated March 22, 2010, the staff quoted Sections 4.0 and 5.0 of the Safety Evaluation Report dated June 17, 1983. Section 4.0 states that fire protection in Fire Zone P1E Elevation 84' Auxiliary Building Electrical Penetration Area is provided, in part, by a manually operated total flooding CO2 extinguishing system and Section 5.0 states that fire protection in Fire Area P1B 4 kV Switchgear Room is provided, in part, by a manually operated CO2 extinguishing system.
The staff requested that the applicant verify whether the carbon dioxide fire suppression systems listed above are within the scope of license renewal in accordance with 10 CFR 54.4(a) and whether they are subject to an AMR in accordance with 10 CFR 54.21(a)(1). The staff further requested that, if these systems are not within the scope of license renewal and are not subject to an AMR, the applicant provide justification for the exclusion.
In a letter dated April 19, 2010, the applicant responded to RAI 2.3.3.12-3 and stated:
A plant modification was completed in 2008 that replaced CO 2 fire suppression systems located in the Auxiliary Building Penetration Areas and in the 4 kV Switchgear Rooms with closed head dry pipe pre
-action type sprinkler syste ms. These sprinkler systems serve the Auxiliary Building Electrical Penetration Areas Structures and Components Subject to Aging Management Review 2-57 at elevation 78', the 4 kV Switchgear Rooms at elevation 64', and also the 460 Volt Switchgear Rooms at elevation 84' for Salem Units 1 and 2. The sprinkler systems are in the scope of license renewal and are subject to AMR. The Salem Unit 1 sprinkler systems are shown on drawing LR
-205222, sheet 1 at H
-3 and H-4. The Salem Unit 2 sprinkler systems are shown on drawing LR
-205222, sheet 2 at B
-2 and B-3. These systems are designated as green on the drawings indicating that they are within the scope of license renewal and are subject to an AMR. The staff reviewed the applicant response to RAI 2.3.3.12-3. The applicant stated that the carbon dioxide fire suppression systems located in the auxiliary building penetration areas and in the 4 kV switchgear rooms were replaced by closed head dry pipe pre
-action type sprinkler systems. Given the fact that these carbon dioxide fire suppression systems are no longer in use, the staff finds the applicant response to RAI 2.3.3.12-3 acceptable for the purpose of determining whether the applicant has adequately identified the fire protection system components within the scope of license renewal In RAI 2.3.3.12-4 of its letter dated March 22, 2010, the staff quoted Sections 1.3 and 6.2 of the Safety Evaluation Report dated July 20, 1989. Section 1.3 states that:
  "Where non-rated hatches exist, either the area below is protected by an automatic fire suppression system or potential fire spread up through the hatch will not affect redundant shutdown systems-
" and Section 6.2 states that:
  "...the licensee proposed to implement the following modifications:
Expand the existing wet
-piping sprinkler system in the charging pump area to provide full coverage around the pump-
" The staff requested that the applicant verify whether the fire protection suppression systems listed above are within the scope of license renewal in accordance with 10 CFR 54.4(a) and whether they are subject to an AMR in accordance with 10 CFR 54.21(a)(1). The staff further requested that, if these fire suppression systems not within the scope of license renewal and are not subject to an AMR, the applicant provide justification for the exclusion.
In a letter dated April 19, 2010, the applicant responded to RAI 2.3.3.12-4 and stated:
Automatic fire suppression systems do not exist in areas below non
-rated steel hatches at Salem Unit 1 and Unit 2. Engineering evaluation of the non
-rated steel hatch configurations has determined that, under credible fire scenarios, and with proper control of combustible loading, fires will not spread up through hatches and affect redundant shutdown equipment. Plant areas near the subject hatch locations have been designated as combustible control zones for controlling the plant configuration relative to maintenance of low combustible loads. Implementation of these combustible control zones ensures the integrity of the non
-rated steel hatches during a fire and eliminates the need for automatic fire suppression systems in areas below the hatches.
The expanded wet
-piping sprinkler systems in the charging pump area and the enhanced sprinkler systems that protect the auxiliary feedwater pumps are in the scope of license renewal and are subject to an AMR. These systems are designated as green Structures and Components Subject to Aging Management Review 2-58 on drawings LR
-205222, Sheet 1 at F
-4, C-4 (charging pump area) and Sheet 2 at D
-6, D-8 (auxiliary feedwater pumps).
The staff reviewed the applicant response to RAI 2.3.3.12-4. Based on the applicant's statement that there are no automatic fire suppression systems below the non
-rated hatches, the staff finds the applicant response to this portion of RAI 2.3.3.12-4 acceptable.
In regard to the wet
-pipe sprinkler system in the charging pump area and the sprinkler systems that protect the auxiliary feedwater pumps, the applicant stated that these fire protection suppression systems are within the scope of license renewal and subject to an AMR. Based on its review, the staff finds the applicant response to this portion of RAI 2.3.3.12-4 acceptable.
Based on its review
, the staff found that the applicant had addressed and resolved each item in response to RAI as discussed above. Therefore, the staff found response to the RAI 2.3.3.12-4 acceptable for the purpose of determining whether the applicant has adequately identified the fire protection system components within the scope of license renewal.
2.3.3.12.3 Conclusio n The staff reviewed the LRA, UFSAR, RAI responses, and boundary drawings to determine whether the applicant failed to identify any components within the scope of license renewal. In addition, the staff's review determined whether the applicant failed to identify any components subject to an AMR. On the basis of its review, the staff concludes the applicant has appropriately identified the fire protection system and components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the fire protection system and components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.13  Fresh Water System 2.3.3.13.1 Summary of Technical Information in the Application LRA Section 2.3.3.13 describes the fresh water system. The fresh water system is a normally operating mechanical system designed to provide the plants with a source of water for potable, sanitary, fire protection or process make
-up use. The fresh water system has interfaces with the following systems and components:  chilled water system, demineralized water system, fire protection system, heating water & heating steam system, main condensate and feedwater, main condenser and air removal system, main steam system, main turbine and auxiliaries system, non
-radioactive drain system, non
-radioactive liquid waste system, and the steam generators.
The purpose of the fresh water system is to provide the plants with a source of raw water for non-potable use, or for further treatment for potable or plant use. The fresh water system accomplishes this purpose via production wells, pumps, heat exchangers, tanks, piping, piping components, and plumbing fixtures.
LRA Table 2.3.3-13 identifies the components subject to an AMR for the fresh water system by component type and intended function.
 
Structures and Components Subject to Aging Management Review 2-59 2.3.3.13.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the fresh water system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.14  Fuel Handling and Fuel Storage System 2.3.3.14.1 Summary of Technical Information in the Application LRA Section 2.3.3.14 describes the fuel handling and fuel storage (FHFS) system which consists of the following plant systems:  fuel handling and fuel handling tools system.
The FHFS system is a mechanical system designed to manipulate and store new and spent fuel and to control fuel geometry when the fuel is not in the core.
The purpose of the FHFS System is to provide a safe, effective means of storing, transporting and handling fuel from the time it reaches the plant in an unirradiated condition until it leaves the plant after post
-irradiation cooling. The FHFS system controls fuel storage positions to assure a geometrically safe configuration with respect to criticality, ensure adequate shielding of irradiated fuel for plant personnel to accomplish normal operations, prevent mechanical damage to the stored fuel that could result in significant release of radioactivity from the fuel, and provide means for the safe handling of new and irradiated fuel.
LRA Table 2.3.3-14 identifies the components subject to an AMR for the FHFS system by component type and intended function.
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 applicable boundary drawings, the staff concludes that the applicant has appropriately identified the FHFS system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.15  Fuel Handling Ventilation System 2.3.3.15.1 Summary of Technical Information in the Application LRA Section 2.3.3.15 describes the fuel handling ventilation (FHV) system which consists of the fuel handling ventilation supply system, the fuel handling ventilation exhaust system, and ventilation systems for the store room and vent sampling room. The FHV system is a normally operating mechanical system designed to maintain the fuel handling building (FHB) at a slight negative pressure with respect to atmosphere to prevent uncontrolled release of radioactive material from the FHB. The FHV system also serves to maintain FHB within the design temperature limits during fuel handling activities, route air from the spent fuel pool and high Structures and Components Subject to Aging Management Review 2-60 contamination areas to the filter Unit before releasing it to the atmosphere, direct air flow from cleaner or less contaminated areas to areas of higher contamination, and provide ventilation for the storeroom and vent sampling enclosure.
The purpose of the FHV system is to maintain the FHB at a slight negative pressure with respect to atmosphere to assure inleakage of air rather than outleakage. The FHV system accomplishes this purpose by using two fans and two filter trains to exhaust air from the FHB.
LRA Table 2.3.3-15 identifies the components subject to AMR for the FHV system by component type and intended function.
2.3.3.15.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the FHV system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.16  Fuel Oil System 2.3.3.16.1 Summary of Technical Information in the Application LRA Section 2.3.3.16 describes the fuel oil (FO) system. The FO system is a normally operating mechanical system designed to receive, store and condition fuel oil for eventual transfer.
The purpose of the FO system is to transfer fuel oil to the following systems and equipment:  gas turbine (Unit 3), house heating Boilers, TSC emergency diesel generator, emergency diesel generator & auxiliaries system, fire protection system, circulating water intake heating boiler and service water intake hot air furnace. The FO system accomplishes this purpose by providing pumps, filters and associated piping
, and components necessary to unload, filter, and transfer fuel oil.
LRA Table 2.3.3-16 identifies the components subject to an AMR for the FO system by component type and intended function.
2.3.3.16.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the FO system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
 
Structures and Components Subject to Aging Management Review 2-61 2.3.3.17  Heating Water and Heating Steam System 2.3.3.17.1 Summary of Technical Information in the Application LRA Section 2.3.3.17 describes the heating water and heating steam (HWHS) system which consists of the following systems:  house heating boiler and heating water/heating steam (heating boilers). The HWHS system is a normally operating mechanical system designed to provide the site with a source of hot water to maintain area and equipment temperatures within normal limits, and steam to support process heaters.
The purpose of the HWHS system is to provide the site with a source of hot water and steam to maintain area, equipment, and process temperatures within normal limits. The HWHS system accomplishes this purpose by using either bleed steam from one of the operating Unit turbines, or from the oil fired
-heating boilers to supply steam to process heaters, to heat water that is circulated by pumps, piping, and associated controls, and to heat exchangers and area heaters to maintain tank content and area temperatures.
LRA Table 2.3.3-17 identifies the components subject to an AMR for the HWHS system by component type and intended function.
2.3.3.17.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the HWHS system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.18  Non-radioactive Drain System 2.3.3.18.1 Summary of Technical Information in the Application LRA Section 2.3.3.18 describes the non
-radioactive drain system. The non-radioactive drain system is a normally operating mechanical system designed to provide non
-contaminated drainage control and management for the Salem site.
The purpose of the non
-radioactive drain system is to collect, forward, and as required, treat miscellaneous drainage from buildings, equipment, and yard areas for drainage to be discharged to the Delaware River in compliance with the NJPDES permit. The non-radioactive drain system accomplishes this purpose by providing drains, drain flowpaths, sumps, sump pumps, and discharge flowpaths from buildings and yard areas, and as required, by treating these drains via the oil
-water separator, or by the non
-radioactive liquid waste system prior to discharge to the Delaware River.
LRA Table 2.3.3-18 identifies the components subject to an AMR for the non
-radioactive drain system by component type and intended function.
 
Structures and Components Subject to Aging Management Review 2-62 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 applicable boundary drawings, the staff concludes that the applicant has appropriately identified the non
-radioactive drain system mechanical components within the scope of license renewal, as required by 10 C FR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.19  Radiation Monitoring System 2.3.3.19.1 Summary of Technical Information in the Application LRA Secti on 2.3.3.19 describes the radiation monitoring (RM) system. The RM system is a normally operating system designed to detect, compute, indicate, annunciate, and record radiation levels at selected locations inside the plant.
The purpose of the RM system is to detect, compute, indicate, annunciate, and record radiation levels at selected locations inside the plant. The RM system accomplishes this purpose by providing process, process filter, and area radiation monitors. It also provides interlock signals to support intended functions on high radiation level detection.
LRA Table 2.3.3-19 identifies the components subject to an AMR for the RM system by component type and intended function.
2.3.3.19.2 Conclusion Based on the results of the staff evaluation discussed in LRA Section 2.3 , and on a review of the UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the RM system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.20  Radioactive Drain System 2.3.3.20.1 Summary of Technical Information in the Application LRA Section 2.3.3.20 describes the radioactive drain (RD) system. The RD system is a mechanical normally operating system designed to provide contaminated drainage control and management for the auxiliary building, containment structure, penetration areas, and the fue l handling building, provide flood protection for equipment in the auxiliary and fuel handling buildings, and provide flowpaths from various safety
-relief valves to the radwaste system.
The purpose of the RD system is to collect and forward miscellaneous drainage from buildings and equipment, and safety
-relief valve discharges to the radwaste system. The RD system accomplishes this purpose by providing drains, drain flowpaths, pumps, and discharge flowpaths from buildings and equipment, including safe ty-relief valve discharges, to the radwaste system.
 
Structures and Components Subject to Aging Management Review 2-63 LRA Table 2.3.3-20 identifies the components subject to an AMR for the RD system by component type and intended function
. 2.3.3.20.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.20, UFSAR Sections 3.4.3.1, 6.3.5.4, and 9.3.3, 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 an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.
In RAI 2.3.3.20-01, dated April 14, 2010, the staff noted LRA drawing LR
-205227 (SH3) shows the RCP lift pumps within scope for 10 CFR 54.4(a)(1) or (a)(3). However, the connected water separators and piping to trench 1WDE17 are not within scope. Drawing LR
-205327 (SH3) does not show the RCP oil collection system, water separators and associated piping and components within scope. The applicant was requested to provide additional information to clarify why these nonsafety
-related piping and components that contain water and oil, and are located inside structures that contain safety
-related SSCs, are not included within scope for potential spatial interaction under criterion 10 CFR 54.4(a)(2).
In its response dated May 12, 2010, the applicant stated the boundary drawings were incorrectly shown. The Unit 1 RCP oil lift pumps' oil and water separators and piping leading to trench 1WDE17 have been included as within the scope of license renewal under 10 CFR 54.4(a)(3). The Unit 2 RCP oil lift pumps' oil collection system to trench 2WDE17 have also been included within the scope of license renewal under 10 CFR 54.4(a)(3). LRA Table 2.3.3-12 was revised to include a component type "tanks
." Based on its review, the staff finds the applicant's response to RAI 2.3.3.20-01 acceptable because the components in question up to the trenches have been included within scope. Therefore, the staff's concern described in RAI 2.3.3.20-01 is resolved.
In RAI 2.3.3.20-02, dated April 14, 2010, the staff noted four instances of piping within scope drawing continuations to not within scope on the continuation drawing. The applicant was requested to clarify the scoping classification for these pipe sections.
In its response dated May 12, 2010, the applicant stated that the four instances resulted from two lines for which the highlighting was incorrectly reversed. The applicant stated the drawings have been corrected to show the continued piping as within scope for 10 CFR 54.4(a)(2).
Based on its review, the staff finds the applicant's response to RAI 2.3.3.20-02 acceptable because the applicant explained that the highlighting of the lines in question had been reversed and the drawings have been corrected. Therefore, the staff's concern described in RAI 2.3.3.20-02 is resolved.
In RAI 2.3.3.20-03, dated April 14, 2010, the staff noted two instances of 10 CFR 54.4(a)(1) or (a)(3) piping continued as 10 CFR 54.4(a)(2) piping on the continuation drawing. The applicant was requested to clarify the scoping classification for these pipe sections.
In its response dated May 12, 2010, the applicant stated the drain lines from the primary water storage tank (PWST), are shown incorrectly as within scope for 10 CFR 54.4(a)(1) or (a)(3).
Structures and Components Subject to Aging Management Review 2-64 The applicant stated that the drawing has been revised to show these drain lines as within the scope of license renewal under 10 CFR 54.4(a)(2) up to the drain header.
Based on its review, the staff finds the applicant's response to RAI 2.3.3.20-03 acceptable because the applicant described the scoping changes and indicated the drawings had been corrected. Therefore, 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, RAI responses, and boundary drawings to determine whether the applicant failed to identify any components within the scope of license renewal. In addition, the staff's review determined whether the applicant failed to identify any components subject to an AMR. On the basis of its review, the staff concludes the applicant has appropriately identified the RD system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the RD components subject to an AMR in accordance with the requirements stated in
 
10 CFR 54.21(a)(1).
2.3.3.21  Radwaste System 2.3.3.21.1 Summary of Technical Information in the Application LRA Section 2.3.3.21 describes the radwaste system which consists of the following plant systems associated with the processing of radioactive waste products:  the boron recovery system, the waste liquid (radioactive) system, the waste gas (radioactive) system, and the waste solid (radioactive) system. The radwaste system is a normally operating mechanical system designed to provide the equipment necessary to collect, process, and prepare radioactive liquid, gaseous, and solid wastes for disposal.
The primary purpose of the radwaste system is to manage the collection and processing of the liquid waste and gaseous waste from the RCS. The radwaste system accomplishes its purpose with a variety of tanks, piping, and piping components.
LRA Table 2.3.3-21 identifies the components subject to an AMR for the radwaste system by component type and intended function.
2.3.3.21.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.21, UFSAR Sections 11.2, 11.3, 11.5, and 9.3.4.2, 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 necessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.
In RAI 2.3.3.21-01, dated April 14, 2010, the staff noted two instances of within scope pneumatic tubing continuing to other drawings where the continuations were not within scope. The applicant was requested to clarify the scoping classification for these pneumatic tubing sections. In its response dated May 12, 2010, the applicant stated that in both instances the boundary drawing incorrectly shows the pneumatic tubing as within the scope of license renewal under Structures and Components Subject to Aging Management Review 2-65 10 CFR 54.4(a)(2). The pneumatic tubing is not within the scope of license renewal because it does not have the potential for spatial interaction since it does not contain fluids and does not provide structural support to safety
-related components. The drawing has been revised to reflect that this pneumatic tubing is not within scope.
Based on its review, the staff finds the applicant's response to RAI 2.3.3.21-01 acceptable because the applicant clarified that this pneumatic tubing was incorrectly shown as within scope. Therefore, the staff's concern described in RAI 2.3.3.21-01 is resolved.
2.3.3.21.3 Conclusion The staff reviewed the LRA, UFSAR, RAI response, and boundary drawings to determine whether the applicant failed to identify any components within the scope of license renewal. In addition, the staff's review determined whether the applicant failed to identify any components subject to an AMR. On the basis of its review, the staff concludes the applicant has appropriately identified the radwaste system components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the radwaste mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.22  Sampling System 2.3.3.22.1 Summary of Technical Information in the Application LRA Section 2.3.3.22 describes the sampling system which consists of the following plant systems: sampling and post
-accident sampling. Salem, Units 1 and 2 no longer operate the post-accident sampling system becau se it was removed from the current licensing basis, and it was physically drained and disconnected from the plant. The major components of the sampling system are heat exchangers, piping, valves, and piping components. The sampling system is a normally operating mechanical system designed to obtain liquid and gas samples for laboratory analyses of chemistry and radiochemistry conditions of the reactor coolant, residual heat removal, chemical and volume control, safety injection, demineralized water, main condensate and feedwater, main steam, and steam generators systems. Samples can be provided under operating conditions from full power to cold shutdown.
The purpose of the sampling system is to provide liquid and gas samples from various locations in the plant to designated locations, including online analytical equipment and grab samples for analysis, for purposes of guidance in operation of the reactor coolant, residual heat removal, component cooling, chemical and volume control, main steam, safety injection, and steam generators systems. The sampling system also provides containment isolation.
LRA Table 2.3.3-22 identifies the components subject to an AMR for the sampling system by component type and intended function.
2.3.3.22.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.22, UFSAR Sections 9.3.2 and 9.3.6, 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 necessary to complete the review of the applicant's scoping and screening results. 
 
Structures and Components Subject to Aging Management Review 2-66 In RAI 2.3.3.22-01, dated April 14, 2010, the staff noted on drawings LR
-205244 (SH1) and LR-205344 (SH1), 3/8 inch lines as within scope for 10 CFR 54.4(a)(2) and connected at three-way valves with a 1/2 inch
-O.D. tubing which is shown as not within scope. In both cases, two lines exiting the three
-way valve are in scope for 10 CFR 54.4(a)(2), while the third is not. The applicant was requested to provide additional information to clarify the scoping classification of this pipe section.
In its response dated May 12, 2010, the applicant stated line 6714 Y
-N on drawing LR
-205244 (SH1) was previously used to conduct samples from the Nos.
11 and 12 RHR heat exchanger outlets to the Salem Unit 1 Post Accident Sampling System (PASS). The PASS has been abandoned in place
, and the port of the three
-way valve connected to line 6714 Y
-N is kept in a closed position to provide isolation from the PASS equipment. The Salem Unit 2 PASS has also been abandoned in place, so the same case exists for drawing LR
-205344 (SH1). Neither line contains water, steam, or oil and does not provide structural support to safety
-related components. Therefore, the lines are correctly shown as not within scope for license renewal under 10 CHR 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 the scoping classification of the pipe in question. 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, RAI response, and boundary drawings to determine whether the applicant failed to identify any components within the scope of license renewal. In addition, the staff's review determined whether the applicant failed to identify any components subject to an AMR. On the basis of its review, the staff concludes the applicant has appropriately identified the sampling system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the sampling system mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.23  Service Water System 2.3.3.23.1 Summary of Technical Information in the Application LRA Section 2.3.3.23 describes the service water (SW) system. The SW system is a normally operating auxiliary system designed to provide cooling water from the Delaware River to safety-related and nonsafety
-related plant components.
The purpose of the SW system is to circulate cooling water from the river through both safety-related and nonsafety
-related heat exchangers and back to the river. The SW system consists of three parallel loops:  two nuclear headers and one non
-nuclear header. The SW system accomplishes this purpose by providing screened river water to the service water pump suctions and then circulating river water through each nuclear header which includes a component cooling heat exchanger, lube oil and gear oil coolers for the ECCS pumps, ECCS pump room coolers, diesel generator heat exchangers, containment fan coil units, and chiller condensers. Additionally, service water can provide cooling for the emergency air compressor, when it is aligned manually in the field. There are also two service water accumulators (one for each nuclear header), which maintain the containment fan coil Unit piping filled in the containment during the diesel generator sequencing following a DBE.
Structures and Components Subject to Aging Management Review 2-67 LRA Table 2.3.3-23 identifies the components subject to an AMR for the SW system by component type and intended function.
2.3.3.23.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.23, UFSAR Section 9.2.1 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 necessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.
In RAI 2.3.3.23-01, dated April 14, 2010, the staff noted on drawing LR
-205212 (SH1) a section of 10 CFR 54.4(a)(1) 6 inch service water line that continues to drawing LR
-205309 (SH3), where the same line continuation is not within scope of license renewal. The applicant was requested to provide additional information to clarify the scoping classification of this pipe section. In its response dated May 12, 2010, the applicant stated that the continuation of the 6 inch service water line was incorrectly shown as not within scope on the drawing and that this line should be within scope for 10 CFR 54.4(a)(2) for functional support. The applicant stated the drawing has been revised to show the 6 inch line as within scope for license renewal up to the circulating water river discharge header and including all the components inbetween. This revision did not result in identifying any new component types subject to AMR. The applicant also revised the third system intended function for clarity.
Based on its review, the staff finds the applicant's response to RAI 2.3.3.23-01 acceptable because the applicant corrected the scoping classification of the pipe line in question. Therefore, the staff's concern described in RAI 2.3.3.23-01 is resolved.
In RAI 2.3.3.23-02, dated April 14, 2010, the staff noted on Unit 1 drawing LR
-205239 (SH1), 2 inch-1SW1460 as within scope for 10 CFR 54.4(a)(1). Connected to 2 inch- CFR 54.4(a)(2) 2 inch-1295, 2 inch-1292, 2 inch-1293 and 3/4 inch-1291 lines. On Unit 2 drawing LR
-205339 (SH1), 2 inch-1053 is within scope for 10 CFR 54.4(a)(1). Connected to 2 inch-1053 are 10 CFR 54.4(a)(2) 2 inch-1WL1295, 2 inch-1074, 3/4 inch-1318 lines. The 10 CFR 54.4(a)(2) scoping boundary ends before these lines reach the waste monitor tanks or pumps. No anchor point was identified between the end of the 10 CFR 54.4(a)(2) scoping boundary and the safety-nonsafety interface. The applicant was requested to provide additional information to locate the seismic anchors or anchored components between the ends of the 10 CFR 54.4(a)(2) scoping boundary and the safety
-nonsafety interfaces.
The applicant's response, dated May 12, 2010, described the location of the seismic anchors, which are within the existing (a)(2) scoping boundary.
This conforms to the applicant's methodology and did not result in the inclusion of any additional components within the scope of license renewal.
Based upon its review, the staff finds the applicant's response to RAI 2.3.3.23-02 acceptable. In RAI 2.3.3.23-03, dated April 14, 2010, the staff noted on Unit 1 drawing LR
-205242 (SH1) a continuation (1 inch S.L.) from LR
-205209 (SH4) as within the scope for 10 CFR 54.4(a)(2). This line is connected to a 3 inch service water line within scope for 10 CFR 54.4(a)(1). On Unit 2 drawing LR
-205342 (SH1)
, a continuation (1 inch S.L.) from LR
-205209 (SH4) is within scope for 10 CFR 54.4(a)(2). This line is connected to a 1 inch service water line within scope Structures and Components Subject to Aging Management Review 2-68 for 10 CFR 54.4(a)(1). The seismic anchor or anchored component for the two 10 CFR 54.4(a)(2) 1 inch lines could not be located. The applicant was requested to provide additional information to locate the seismic anchors or anchored components between the ends of the 10 CFR 54.4(a)(2) scoping boundary and the safety
-nonsafety interface.
In its response dated May 12, 2010, the applicant described the location of the seismic anchors, which are within the existing (a)(2) scoping boundary.
This conforms with the applicant's methodology and did not result in the inclusion of any additional components within the scope of license renewal.
Based upon its review, the staff finds the applicant's response to RAI 2.3.3.23-03 acceptable.
In RAI 2.3.3.23-04, dated April 14, 2010, the staff noted on drawing LR
-205242 (SH3) a 3/4 inch 10 CFR 54.4(a)(1) line connected to a 10 CFR 54.4(a)(2) line (7003 Y
-N). The seismic anchor or anchored component for the 10 CFR 54.4(a)(2) line could not be located. The applicant was requested to provide additional information to locate the seismic anchor or anchored component between the end of the 10 CFR 54.4(a)(2) scoping boundary and the safety
-nonsafety interface.
In its response dated May 12, 2010, the applicant stated that the tubing beyond the safety-nonsafety interface is non
-seismic and provided the location of the seismic anchor for the 10 CFR 54.4(a)(1) line.
Based on its review, the staff finds the applicant's response to RAI 2.3.3.23-04 acceptable because the applicant clarified that the tubing was non-seismic and provided the location for the 10 CFR 50.54(a)(1) seismic anchor. Therefore, the staff's concern described in RAI 2.3.3.23-04 is resolved.
2.3.3.23.3 Conclusion The staff reviewed the LRA, UFSAR, RAI response, and boundary drawings to determine whether the applicant had failed to identify any components within the scope of license renewal. In addition, the staff's review determined that the applicant had not failed to identify any components that should be subject to an AMR. On the basis of its review, the staff concludes the applicant has appropriately identified the SW system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the SW system mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.24  Service Water Ventilation System 2.3.3.24.1 Summary of Technical Information in the Application LRA Section 2.3.3.24 describes the service water ventilation (SWV) system which consists of four service water intake compartments. The SWV system for each compartment consists of an outside air intake penthouse, power
-operated intake and exhaust dampers, and two exhaust fans discharging to the outdoors. The SWV system is a normally operating system designed to remove waste heat from the SW system components located in the service water intake Structure (SWIS).
The purpose of the SWV system is to remove waste heat from the SW system components located in the SWI S. The SWV system accomplishes this purpose by exhausting air from the SWIS service water intake compartments and control rooms.
 
Structures and Components Subject to Aging Management Review 2-69 LRA Table 2.3.3-24 identifies the components subject to an AMR for the SWV systems by component type and intended function.
2.3.3.24.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the SWV system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the SWV system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.25  Spent Fuel Cooling System 2.3.3.25.1 Summary of Technical Information in the Application LRA Section 2.3.3.25 describes the spent fuel cooling (SFC) system. The SFC system is a normally operating mechanical system designed to remove from the spent fuel pool the heat generated by stored spent fuel elements. The SFC system consists of the following three loops:  the pool cooling loop, the purification loop and the skimmer loop.
The purpose of the SFC system is to maintain spent fuel pool temperatures within design limits. The purpose of the pool cooling loop is to remove decay heat from the spent fuel stored in the spent fuel pool. The purpose of the purification loop is to purify water from the spent fuel pool, transfer pool and refueling water storage tank (RWST). The purpose of the skimmer loop is to maintain clarity of the spent fuel pool water by removing particles floating on the surface of the pool water.
LRA Table 2.3.3-25 identifies the components subject to an AMR for the SFC system by component type and intended function.
2.3.3.25.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.25, UFSAR Section 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 an area in which additional information was necessary to complete the review of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.
In RAI 2.3.3.25-01, dated April 14, 2010, the staff noted on drawing LR
-205333(SH 1) two instances of anchors for nonsafety
-related piping connected to safety
-related piping that could not be located. The applicant was requested to provide additional information to locate the seismic anchors or anchored components between the ends of the 10 CFR 54.4(a)(2) scoping boundary and the safety
-nonsafety interface.
In its response dated May 12, 2010, the applicant provided the location of the seismic anchors, which are within the existing (a)(2) scoping boundary.
This conforms to the applicant's methodology and did not result in the inclusion of any additional components within the scope of license renewal.
Based upon its review, the staff finds the applicant's response to RAI 2.3.3.25-01 acceptable.
Therefore, the staff's concern described in RAI 2.3.3.25-01 is resolved.
Structures and Components Subject to Aging Management Review 2-70 2.3.3.25.3 Conclusion The staff reviewed the LRA, UFSAR, RAI response, and boundary drawings to determine whether the applicant failed to identify any components within the scope of license renewal. In addition, the staff's review determined whether the applicant failed to identify any components subject to an AMR. On the basis of its review, the staff concludes the applicant has appropriately identified the SFC system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the SFC system mechanical components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.3.26  Switchgear and Penetration Area Ventilation System 2.3.3.26.1 Summary of Technical Information in the Application LRA Section 2.3.3.26 describes the switchgear and penetration area ventilation (SPAV) system. The SPAV system is a safety
-related mechanical, normally operating system designed to maintain acceptable levels of temperature and cleanliness in the switchgear rooms, electrical penetration area, and the ventilation equipment room (chiller room).
The purpose of the SPAV system is to maintain acceptable levels of temperature and cleanliness in the switchgear rooms, electrical penetration area, and the ventilation equipment room (chiller room). This is achieved through two supply fans; one switchgear room exhaust fan and one electrical penetration exhaust fan to maintain area temperatures under all conditions. The SPAV system also provides a slightly positive pressure and isolation capabilities for fire conditions in the switchgear rooms and electrical penetration areas.
LRA Table 2.3.3-26 identifies the components subject to an AMR for the SFC system by component type and intended function.
2.3.3.26.2 Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the SPAV system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the SPAV system components subject to an AMR in accordance with the requirements stated in 10 CF R 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:
2.3.4.1 auxiliary feedwater system 2.3.4.2 main condensate and feedwater system 2.3.4.3 main condenser and air removal system 2.3.4.4 main steam system 2.3.4.5 main turbine and auxiliaries system
 
Structures and Components Subject to Aging Management Review 2-71 2.3.4.1  Auxiliary Feedwater System 2.3.4.1.1  Summary of Technical Information in the Application LRA Section 2.3.4.1 describes the auxiliary feedwater (AFW) system. The AFW system is a standby, steam and power conversion mechanical system designed to provide feedwater to the steam generators for heat removal from the RCS under normal and accident conditions. These accident conditions include the loss of normal feedwater, steam generator tube rupture, main steam or feedwater line break, and small break LOCA. The AFW system is comprised of thre e pumps (two motor
-driven pumps and one turbine
-driven pump), one storage tank, and the necessary piping, valves, and instrumentation designed to provide two redundant cooling loops. The loops are designed such that each motor
-driven pump is capable of discharging through a flow nozzle into two lines directing flow into two steam generators. The turbine
-driven pump provides flow to all four steam generators.
LRA Table 2.3.4-1 identifies the components subject to an AMR for the AFW system by component type and intended function.
2.3.4.1.2  Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the AFW system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the AFW system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.4.2  Main Condensate and Feedwater System 2.3.4.2.1  Summary of Technical Information in the Application LRA Section 2.3.4.2 describes the main condensate and feedwater (MCFW) system. The MCFW system is a normally operating mechanical system designed to maintain water level in the steam generators throughout all modes of normal plant operation. The MCFW system is comprised of three condensate pumps, three parallel strings of low pressure feedwater heaters (five heaters per string), two feedwater pumps, three parallel strings of high pressure feedwater heaters (one heater per string) and the required piping, valves, instrumentation, and controls.
The purpose of the MCFW system is to maintain steam generator water level during all modes of normal plant operation. The MCFW system accomplishes this by heating deaerated condensate from the main condenser and delivering it to the steam generators. The MCFW system delivers the water to the steam generators to match the steam demand for the turbine load. LRA Table 2.3.4-2 identifies the components subject to AMR for the MCFW system by component type and intended function.
2.3.4.2.2  Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has Structures and Components Subject to Aging Management Review 2-72 appropriately identified the MCFW system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the MCFW system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.4.3  Main Condenser and Air Removal System 2.3.4.3.1  Summary of Technical Information in the Application LRA Section 2.3.4.3 describes the main condenser and air removal (MCAR) system which consists of two plant systems:  main condenser and condenser air removal. The MCAR system is comprised of the steam side of the main condenser including the three condenser hot wells , the three condenser vacuum pumps, one priming tank vacuum pump, waterbox priming tank and the associated valves and piping. The MCAR system is a normally operating mechanical system designed primarily to condense and deaerate steam from the main turbine.
The purpose of the main condenser portion of the MCAR system is to recover water used in the steam cycle by condensing and deaerating unused steam. The purpose of the condenser air removal portions of the MCAR system is to allow the main condenser to operate at vacuum for peak efficiency.
LRA Table 2.3.4-3 identifies the components subject to an AMR for the MCAR system by component type and intended function.
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 applicable boundary drawings, the staff concludes that the applicant has appropriately identified the MCAR system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the MCAR system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.4.4  Main Steam System 2.3.4.4.1  Summary of Technical Information in the Application LRA Section 2.3.4.4 describes the main steam (MS) system. The MS system is comprised of flow restricting nozzles, safety valves, atmospheric relief valves, main steam isolation valves, mixing bottle and the necessary piping, valves and instrumentation designed to provide steam to the high pressure turbine to accomplish its design functions. The MS system is a normally operating mechanical system designed to provide a flow path for the flow of saturated steam between the steam generator outlets to the high pressure turbine inlets. The MS system also supplies saturated steam to steam dump system (turbine bypass), moisture separator reheaters, main steam coils, turbine gland seal system, turbine
-driven auxiliary feedwater pump, steam generator feed pump turbines, and high pressure turbine cylinder heating steam.
The purpose of the MS system is to direct saturated steam from four steam generators to the high pressure turbines. It accomplishes its purpose by directing the steam generated by the steam generators into the high pressure turbine through piping and piping components. Main Structures and Components Subject to Aging Management Review 2-73 steam isolation valves (MSIV) are installed in each MS line at the outlet of each steam generator. The MSIVs close automatically on the initiation of a steam line isolation signal. Flow limiters (venture
-type restrictor) are provided in each steam line. They are designed to increase the margin to departure from nucleate boiling (DNB), and thereby reduce fuel clad damage, by limiting steam flow rate consequent to a steam line rupture and thereby reducing the cooldown rate of the primary system. Flow limiters are also provided with steam flow transmitters, which provide inputs to the reactor protection system.
LRA Table 2.3.4-4 identifies the components subject to an AMR for the MS system by component type and intended function.
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 applicable boundary drawings, the staff concludes that the applicant has appropriately identified the MS system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the MS system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.3.4.5  Main Turbine and Auxiliaries System 2.3.4.5.1  Summary of Technical Information in the Application LRA Section 2.3.4.5 describes the main turbine and auxiliaries (MTA) system which consists of the following plant systems:  turbine electrohydraulic control, gland sealing steam and leak off (turbine), moisture separator reheater steam and drains, turbine auxiliaries cooling, turbine drains, main turbine lube oil, and the main turbine. The MTA system is a normally operating mechanical system designed to utilize steam from the MS system to provide motive force for the main generator to generate electrical power for distribution to the grid.
The overall purpose of MTA system is to provide motive force for the main generator to generate electrical power for distribution to the grid. The purpose of the turbine electrohydraulic control system is to control turbine valve movement, which in turn controls main steam flow at the inlet to the main turbine. The purpose of the gland sealing steam and leak off (turbine) system is to use main steam to seal the annular openings where the main turbine shaft emerges from the casings, preventing steam outleakage and air inleakage along the shaft. The purpose of the moisture separator reheater steam and drains system is to dry and reheat main steam from the outlet of the high pressure turbine and supply it to the low pressure turbines to increase cycle efficiency. The purpose of the turbine auxiliaries cooling system is to provide cooling water to the turbine generator auxiliary components, as well as other plant components.
LRA Table 2.3.4-5 identifies the components subject to an AMR for the MTA system by component type and intended function.
2.3.4.5.2  Conclusion Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has appropriately identified the MTA system mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the Structures and Components Subject to Aging Management Review 2-74 MTA system components subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
2.4  Scoping and Screening Results:  Structures This Section documents the staff's review of the applicant's scoping and screening results for structures. Specifically, this Section describes the following structures:
auxiliary building component supports commodity group containment structure fire pump house fuel handling building office buildings penetration areas pipe tunnel piping and component insulation commodity group station blackout (sbo) compressor building service building service water accumulator enclosures service water intake shoreline protection and dike switchyard turbine building yard structures In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant identified and listed passive, long
-lived structures and components SCs that are within the scope of the extended period of operation and subject to an AMR. To verify that the applicant properly implemented its methodology, the staff focused its review on the implementation results. This approach allowed the staff to confirm that there were no omissions of structural components that meet the scoping criteria and are subject to an AMR.
The staff's evaluation of the information provided in the license renewal application (LRA) was performed in the same manner for all structures. The objective of the review was to determine if the structural components that appeared to meet the scoping criteria specified in the rule were identified by the applicant as being within the scope of license renewal, in accordance with 10 CFR 54.4. Similarly, the staff evaluated the applicant's screening results to verify that all long-lived, passive SCs were subject to an AMR in accordance with 10 CFR 54.21(a)(1).
To perform its evaluation, the staff utilized the guidance in Section 2.4, "Scoping and Screening Results:  Structures
," of the SRP-LR and reviewed the applicable LRA sections, focusing its review on components that had not been identified as within the scope of license renewal
. The staff reviewed Salem Unit 1 and Unit 2 UFSAR for each structure to determine if the applicant had omitted components, with intended functions delineated under 10 CFR 54.4(a), from the scope of license renewal. The staff also reviewed the UFSAR to determine if all intended functions delineated in 10 CFR 54.4(a) were specified in the LRA. If omissions were identified, the staff requested additional information to resolve the discrepancies.
 
Structures and Components Subject to Aging Management Review 2-75 Once the staff completed its review of the scoping results, the staff evaluated the applicant's screening results. For those components with intended functions, the staff sought to determine:  (1) if the functions are performed with moving parts or a change in configuration or properties, or (2) if they are subject to replacement based on a qualified life or specified time period, as described in 10 CFR 54.21(a)(1). For those that did not meet either of these criteria, the staff sought to confirm that these structural components were subject to an AMR as required by 10 CFR 54.21(a)(1). If discrepancies were identified, the staff requested additional information to resolve them.
2.4.1  Auxiliary Building 2.4.1.1  Summary of Technical Information in the Application LRA Section 2.4.1 describes the auxiliary building. The auxiliary building, which includes the inner penetration areas, is a reinforced concrete structure located between the Salem Unit 1 and Unit 2 containment structures. The auxiliary building is classified as a Category I (seismic) structure designed to maintain its structural integrity during and following postulated design basis accidents and extreme environmental conditions. The auxiliary building SCs include reinforced concrete elements of the building, cable trays, concrete embedments, masonry walls, doors, hatches, compressible joints and seals, conduit, expansion or control joints, racks, frames, enclosures, structural steel, miscellaneous steel, bolting, penetration sleeves, penetration seals, pipe whip restraints, missile shields, pipe encapsulation sleeves, spray shields, residual heat removal sump pit and liner, pipe alley and trench, roofing membrane, and tube track. Also included in the boundary of this structure are the blowout panels, the roof blowout panel extension, the roof missile shields for diesel intake, exhaust and building ventilation, and the air discharge penthouse.
The purpose of the auxiliary building is to provide structural support, shelter and protection to systems, structures, and components (SSCs) housed within the building during normal plant operation, and during and following postulated design basis accidents and extreme environmental conditions.
LRA Table 2.4-1 identifies the components subject to an AMR for the auxiliary building by component type and intended function.
2.4.1.2  Conclusion The staff followed the evaluation methodology discussed in Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the auxiliary building SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
 
Structures and Components Subject to Aging Management Review 2-76 2.4.2  Component Supports Commodity Group 2.4.2.1  Summary of Technical Information in the Application LRA Section 2.4.2 describes the component supports commodity group which consists of structural elements and specialty components designed to transfer the load applied from a system, structure, or component (SSC) to the building structural element or directly to the building foundation. Supports include seismic anchors or restraints, frames, constant and variable spring hangers, rod hangers, sway struts, guides, stops, design clearances, straps, clamps, and clevis pins. Specialty components include snubbers, sliding surfaces, and vibration isolation elements. The commodity group is comprised of the following supports:
supports for ASME class 1, 2 and 3 piping and components supports for cable trays, conduits, HVAC ducts, tube tracks, instrument tubing and non-ASME piping and components supports for racks, panels, cabinets and enclosures for electrical equipment and instrumentation supports for emergency diesel generators (EDG), HVAC system components, and other miscellaneous mechanical equipment supports for platforms, pipe whip restraints, jet impingement shields, masonry walls, and other miscellaneous structures The purpose of the component supports commodity group is to transfer gravity, thermal, seismic, and other lateral loads imposed on or by the system, structure, or component to the supporting building structural element or foundation. The commodity group provides physical support and shelter for nonsafety
-related SSCs whose failure could prevent satisfactory accomplishment of function(s).
LRA Table 2.4-2 identifies the components subject to an AMR for the component supports commodity group by component type and intended function.
2.4.2.2  Conclusion The staff followed the evaluation methodology discussed in SER Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the component supports commodity group SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
 
Structures and Components Subject to Aging Management Review 2-77 2.4.3  Containment Structure 2.4.3.1  Summary of Technical Information in the Application LRA Section 2.4.3 describes the containment structure. Salem Unit 1 and Unit 2 containment buildings are reinforced concrete containments with a cylindrical wall, a foundation mat, and a hemispherical dome roof. The cylindrical wall, the foundation mat, and the dome roof are reinforced with conventional mild steel reinforcing. The inside surface of the containment building is lined with a carbon steel liner to ensure a high degree of leak tightness in the event of a postulated accident. The nominal liner plate thickness is 1/4 inch at the foundation mat and 1/2 inch at the dome. The lower portions of the cylindrical liner are insulated to avoid buckling of the liner due to restricted radial growth when subjected to a rise in temperature. The containment penetrations include the equipment hatch, personnel airlocks, piping penetrations, including the fuel transfer tube penetration, and electrical penetrations. The purpose of the containment structure is to support and protect the enclosed vital mechanical and electrical equipment, including the reactor vessel, the reactor coolant system, the steam generators, pressurizer, auxiliary and engineered safety features systems required for safe operation and shutdown of the reactor. The containment building also provides a reliable final barrier against the escape of fission products to ensure the leakage limits are not exceeded and fission product releases are within 10 CFR 20 during normal plant operation and 10 CFR 100 (10 CFR 50.67) during the postulated design basis accidents.
LRA Table 2.4-3 identifies the components subject to an AMR for the containment structure by component type and intended function
. 2.4.3.2  Conclusion The staff followed the evaluation methodology discussed in SER Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the c ontainment structure SSCs 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  Fire Pump House 2.4.4.1  Summary of Technical Information in the Application LRA Section 2.4.4 describes the fire pump house. The major components housed in the building include the diesel driven fire pumps, and jockey pumps, associated piping and piping components, controls and instrumentation, electrical panels and enclosures. Additionally, fresh water pumps, fresh water chlorination tanks and associated fresh water piping and piping components, controls and instrumentation, and electrical panels and enclosures are also housed within the building.
The purpose of the fire pump house is to provide structural support, shelter and protection for fire protection system, fresh water system and supporting systems and components.
 
Structures and Components Subject to Aging Management Review 2-78 LRA Table 2.4-4 identifies the components subject to an AMR for the fire pump house by component type and intended function.
2.4.4.2  Staff Evaluation The staff reviewed LRA Section 2.4.12 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP
-LR Section 2.4. During its review of LRA Section 2.4.4, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results for the fire pump house
. In RAI 2.4.4-1, dated March 22, 2010, the staff requested that the applicant provide additional information regarding whether the fire pump house roof insulation had been included in the scope of license renewal and subject to an AMR. Specifically, the staff requested the applicant to indicate whether the component was not included due to oversight and to provide a description of the scoping and AMR if an oversight had occurred. Additionally, the staff requested the applicant to provide the basis for its exclusion, if the applicant concluded that the insulation was excluded from the scope of license renewal. In its response to the RAI, dated Apri l 15, 2010, the applicant stated that the roof insulation was not included within the scope of license renewal and is not subject to an AMR, based on the location of the insulation between the built up roofing and the roof slab. The built up roofing includes the roofing membrane, which prevents water intrusion into the roofing insulation and subsequently, prevents the degradation of the underlying roofing insulation. Furthermore, the applicant indicated in LRA Section 2.4.4 that the roofing membrane of the fire pump house is within the scope of license renewal and is subject to an AMR.
Based on its review, the staff finds the response to RAI 2.4.4-1 acceptable because the insulation is not within the scope of license renewal based on the criteria of 10 CF R 54.4(a)(3) due to the fact that the insulation does not provide physical support, or shelter and protection for SSCs relied upon in safety analyses or plant evaluations that demonstrate compliance with the Commission's regulation for fire protection (10 CFR 50.48). Additionally, those SSCs which do meet the above criteria have been demonstrated by the applicant to have been adequately addressed in Section 2.4.4 of the LRA. The staff's concern described in RAI 2.4.4-1 is resolved.
2.4.4.3  Conclusion The staff reviewed the LRA, UFSAR, and RAI responses, to determine whether the applicant failed to identify any SSCs within the scope of LR. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the fire pump house SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
 
Structures and Components Subject to Aging Management Review 2-79 2.4.5  Fuel Handling Building 2.4.5.1  Summary of Technical Information in the Application LRA Section 2.4.5 describes the fuel handling building which is comprised of two separate fuel handling buildings, Salem Unit 1 and Unit 2. The buildings are mirror images of each other reflected about the east
-west Salem center line. The buildings are classified Category I (seismic) structures, designed to maintain their structural integrity during and following postulated design basis accidents and extreme environmental conditions. Each building contains a spent fuel storage pool, new fuel storage pit, fuel transfer pool, a decontamination pit, a sump room, and compartments that house spent fuel pool cooling equipment and supporting systems. The design of the spent fuel storage pool and the fuel transfer pool includes a leak chase system that collects potential leakage through cracks in the seam welds of the stainless steel liners. The leak chase system consists of stainless steel channels embedded in the slabs and in the walls of the two pools. The design is such that any leakage collected in the channels is directed and discharged through 17 drain lines into the sump room trench outside the spent fuel pool in the fuel handling building.
The purpose of the f uel handling building is to provide structural support, shelter and protection to SSCs housed within it during normal plant operation, and during and following postulated design basis accidents and extreme environmental conditions. This function is provided to the fuel handling and fuels system, spent fuel pool cooling system, fuel handling building heating and ventilation system, compressed air system, and their supporting systems.
LRA Table 2.4-5 identifies the components subject to an AMR for the fuel handling building by component type and intended function.
2.4.5.2  Conclusion The staff followed the evaluation methodology discussed in SER Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the fuel handling building SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.4.6  Office Buildings 2.4.6.1  Summary of Technical Information in the Application LRA Section 2.4.6 describes the office buildings which consist of the controlled facilities building, the clean facilities building, and the administration building.
The purpose of the office buildings is to provide physical support, shelter, and protection for nonsafety-related systems, structures, and components. The buildings also provide shelter and facilities for site management, engineering, chemistry, maintenance, and other site support personnel.
 
Structures and Components Subject to Aging Management Review 2-80 LRA Table 2.4-6 identifies the components subject to an AMR for the office buildings by component type and intended function.
2.4.6.2  Conclusion The staff followed the evaluation methodology discussed in SER Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the office buildings
' SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.4.7  Penetration Areas 2.4.7.1  Summary of Technical Information in the Application LRA Section 2.4.7 describes the penetration areas which consist of two reinforced concrete enclosed areas, Salem Unit 1 south outer penetration area and the Salem Unit 2 north outer penetration area. The areas, or structures, are located at the exit of the main steam system and the main condensate and feedwater system piping from the containments en route to the turbine building. The structures are classified as Category I (seismic) structures, designed to maintain their structural integrity during and following postulated DBEs and extreme environmental conditions. A seismic gap separates the structures from the containment buildings to prevent their interaction during the postulated design basis seismic events.
The purpose of the penetration areas is to support and protect safety
-related main steam, and main condensate and feedwater system piping and components and their supporting mechanical and electrical systems. The structures also provide radiation shielding and protection for the containment structure penetrations.
LRA Table 2.4-7 identifies the components subject to an AMR for the penetration areas by component type and intended function.
2.4.7.2  Conclusion The staff followed the evaluation methodology discussed in SER Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the penetration areas
' 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 2-81 2.4.8  Pipe Tunnel 2.4.8.1  Summary of Technical Information in the Application LRA Section 2.4.8 describes the pipe tunnel as a two-cell reinforced concrete rectangular box Section located west of the containment buildings, and adjacent to the west wall of the auxiliary building. The pipe tunnel is classified as a Category I (seismic) structure.
The purpose of the pipe tunnel is to provide structural support for Salem Unit 1 and Unit 2 refueling water storage tanks, auxiliary feedwater tanks, and primary water storage tanks. The tunnel also provides structural support, shelter, and protection for the service water system piping and piping components, and supporting electrical systems.
LRA Table 2.4-8 identifies the components subject to an AMR for the pipe tunnel by component type and intended function.
2.4.8.2  Conclusion The staff followed the evaluation methodology discussed in SER Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the pipe tunnel 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).
2.4.9  Piping and Component Insulation Commodity Group 2.4.9.1  Summary of Technical Information in the Application LRA Section 2.4.9 describes the piping and component insulation commodity group. The piping and component insulation commodity group is comprised of pre
-fabricated blankets, modules, or panels engineered as integrated assemblies to fit the surface to be insulated and to fit easily against the piping and components. The insulation includes metallic and non-metallic materials.
The purpose of piping and component insulation is to improve thermal efficiency, minimize heat loads on the HVAC systems, provide for personnel protection, prevent freezing of heat traced piping, and protect against sweating of cold piping and components. Insulation of piping within containment penetrations, in conjunction with the penetration cooling system, limits the concrete temperature adjacent to the embedded sleeve to within an allowable limit.
LRA Table 2.4-9 identifies the components subject to an AMR for the piping and component insulation commodity group by component type and intended function.
2.4.9.2  Conclusion The staff followed the evaluation methodology discussed in SER Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the Structures and Components Subject to Aging Management Review 2-82 scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the piping and component insulation commodity group SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.4.10  SBO Compressor Building 2.4.10.1  Summary of Technical Information in the Application LRA Section 2.4.10 describes SBO compressor building. The SBO compressor building is a nonsafety-related structure, designed to commercial grade standards. The structure is separated from safety
-related SSCs such that its failure would not impact a safety
-related function.
The purpose of the SBO compressor building is to provide physical support, shelter, and protection for the SBO diesel
-driven air compressor and its auxiliary systems. The compressor is credited for providing control air during a SBO event. Major components housed inside the building include the SBO diesel driven air compressor, regenerative air dryer, after
-cooler, transformers, distribution panel, disconnect switch, and piping and piping components.
LRA Table 2.4-10 identifies the components subject to an AMR for the SBO compressor building by component type and intended function.
2.4.10.2  Conclusion The staff followed the evaluation methodology discussed in SER Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the SBO compressor 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).
2.4.11  Service Building 2.4.11.1  Summary of Technical Information in the Application LRA Section 2.4.11, describes the service building which is partitioned into office areas, training areas, main access control into the radiological area, maintenance shops, and facilities for personnel occupying the building. Components inside the building are nonsafety
-related except for two auxiliary feedwater system isolation valves within trenches in the basement floor of the building. The service building is nonsafety
-related and is classified as a Category III (seismic) structure.
Structures and Components Subject to Aging Management Review 2-83 The purpose of the service building is to house equipment, tools, and personnel required for supporting operation of Salem Unit 1 and Unit 2. It provides office space and facilities for plant support personnel, training areas, and maintenance shops.
LRA Table 2.4-11 identifies the components subject to an AMR for the service building by component type and intended function.
2.4.11.2  Conclusion The staff followed the evaluation methodology discussed in SER Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the service building SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.4.12  Service Water Accumulator Enclosures 2.4.12.1  Summary of Technical Information in the Application LRA Section 2.4.12 describes the service water accumulator enclosures which consist of two enclosures that house Salem Unit 1 and Unit 2 service water system accumulator tanks. Each enclosure is comprised of structural steel frames, metal siding, prefabricated roof panels, and reinforced concrete slab on grade. The steel frames are supported on reinforced concrete footings founded on soil, and from reinforced concrete walls of the fuel handling building and the auxiliary building. The structural steel frames and plate, the reinforced concrete footings, and other components that provide structural support or shelter and protection for the accumulator tanks are classified Category I (seismic) structures. The remaining portions of the enclosures are nonsafety
-related designed to maintain their structural integrity during DBEs (seismic II/I) to prevent interaction with the safety
-related service water system components.
The purpose of the service water accumulator enclosures is to provide structural support, shelter and protection for safety
-related service water system accumulator tanks and associated service water system piping and piping components. The enclosures also house nonsafety-related SSCs whose failure could impact a safety
-related function.
LRA Table 2.4-12 identifies the components subject to an AMR for the service water accumulator enclosures by component type and intended function.
2.4.12.2  Staff Evaluation The staff reviewed LRA Section 2.4.12 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP
-LR Section 2.4. During its review of the LRA Section 2.4.12, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results for the service water accumulator enclosures.
 
Structures and Components Subject to Aging Management Review 2-84 In RAI 2.4.12-1, dated March 22, 2010, the staff requested that the applicant provide additional information to confirm that the cable trays, conduits, panels, racks, cabinets and other enclosures have been included within the scope of license renewal and subject to an AMR. Specifically, the staff requested the applicant to indicate whether these components were not included due to oversight and to provide a description of the scoping and AMR, if an oversight had occurred. Additionally, the staff requested the applicant to provide the bases for their exclusion, if the applicant concluded that these components were excluded from the scope of license renewal.
In its response to the RAI, dated April 15, 2010, the applicant stated that these components were included within the scope of license renewal and are subject to an AMR due to the fact that these components perform intended functions which meet the criteria found within 10 CFR 54.4(a). Additionally, the applicant indicated that these components were included within Section 2.4.12 of the LRA under the "Miscellaneous Steel (catwalks, handrails, ladders, platforms, etc.)."
Based on its review, the staff finds the response to RAI 2.4.12-1 acceptable because the applicant has clarified that these components are within the scope of license renewal consistent with the criteria outlined in 10 CFR 54.4(a), and subject to an AMR. The staff's concern described in RAI 2.4.12-1 is resolved.
2.4.12.3  Conclusion The staff reviewed the LRA, UFSAR, and RAI responses to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the service water accumulator enclosures SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.4.13  Service Water Intake 2.4.13.1  Summary of Technical Information in the Application LRA Section 2.4.13 describes the service water intake structure as a reinforced concrete structure located along the western shoreline of the facility and on the eastern bank of the Delaware River. The service water intake structure is designed to protect the enclosed portion of the service water system and related vital components under postulated environmental and DBE loadings, and is designated as safety
-related and Category I (seismic).
The purpose of the service water intake structure is to support and protect the enclosed portion of the service water system and its related vital components under postulated environmental and DBE loading conditions and to provide access to a reliable source of cooling water for plant safe shutdown from the Delaware River. Major components housed inside the building include electrical switchgear, miscellaneous electrical equipment and components and their enclosures, instrumentation and their enclosures as applicable, trash racks, service water piping, service water pumps, and the traveling water screen
: s. The service water intake structure also houses or supports nonsafety
-related equipment including cranes and hoists.
 
Structures and Components Subject to Aging Management Review 2-85 LRA Table 2.4-13 identifies the components subject to an AMR for the service water intake by component type and intended functio
: n. 2.4.13.2  Conclusion The staff followed the evaluation methodology discussed in SER Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the service water intake SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.4.14  Shoreline Protection and Dike 2.4.14.1  Summary of Technical Information in the Application LRA Section 2.4.13 describes the shoreline protection and dike as a shoreline protective structural feature comprised primarily of rock, armor stone, steel sheet piles, cofferdams, intake structures, and concrete which is located along the Delaware River shoreline of Artificial Island.
The purpose of the shoreline protection and dike is to provide a flood protection barrier, between the Delaware River and the plant site, which limits wave run
-up during design basis storm surge events to elevations on buildings sealed for external flooding.
LRA Table 2.4-14 identifies the components subject to an AMR for the shoreline protection and dike by component type and intended function.
2.4.14.2  Staff Evaluation The staff reviewed LRA Section 2.4.14 using the evaluation methodology described in SER Section 2.4 and the guidance in SRP
-LR Section 2.4. During its review of the LRA Section 2.4.14, the staff identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results for the shoreline protection and dike.
In RAI 2.4.14-1, dated March 22, 2010, the staff requested that the applicant provide additional information to confirm that the cofferdams have been included within the scope of license renewal and subject to an AMR. Specifically, the RAI requested the applicant to indicate whether the cofferdams were not included due to oversight and to provide a description of the scoping and an AMR, if an oversight had occurred. Additionally, the staff requested the applicant to provide the bas es for their exclusion, if the applicant concluded that these components were excluded from the scope of LR.
In its response to the RAI, dated April 15, 2010, the applicant stated that the cofferdams are included within the scope of license renewal and are subject to an AMR. The applicant indicated that the cofferdams consist of sheet piles, which are listed in Section 2.4-14 of the LRA as being within the scope of license renewal and subject to an AMR due to the fact that Structures and Components Subject to Aging Management Review 2-86 these components perform intended functions which meet the criteria found within 10 CFR 54.4(a). Based on its review, the staff finds the response to RAI 2.4.14-1 acceptable because the applicant has clarified that these components are within the scope of license renewal and subject to an AMR, consistent with the criteria outlined in 10 CFR 54.4(a). The staff's concern described in RAI 2.4.14-1 is resolved.
2.4.14.3  Conclusion The staff reviewed the LRA, UFSAR, and RAI response to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the shoreline protection and dike 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).
2.4.15  Switchyard 2.4.15.1  Summary of Technical Information in the Application LRA Section 2.4.15 describes the switchyard which consists of reinforced concrete and steel components, which include steel piles, equipment foundations, transmission towers, duct banks, manholes, trenches, sumps, structural bolting, embedments, and concrete anchors.
The purpose of the switchyard is to provide physical support, shelter, and protection to the 13KV system and the offsite
-500kV system components and commodities. The systems are relied upon to provide offsite power during SBO event restoration. The offsite
-500kV system consists of three 500 kV transmission lines connected to a breaker
-and-a-half design with four 500 kV-13 kV transforme rs. The offsite
-500kV system receives site generated power and transmits it over three transmission lines to the Public Service Electric and Gas electric transmission network.
LRA Table 2.4-15 identifies the components subject to an AMR for the switchyard by component type and intended function.
2.4.15.2  Conclusion The staff followed the evaluation methodology discussed in SER Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the switchyard 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 2-87 2.4.16  Turbine Building 2.4.16.1  Summary of Technical Information in the Application LRA Section 2.4.16 describes the turbine building as a multi
-story structure approximately 170 feet by 610 feet in plan area, comprised of structural steel framing, precast concrete panels, metal siding, masonry walls, and reinforced concrete walls, slabs, foundation mat, and roof.
The purpose of the building is to provide structural support, shelter, and protection for nonsafety-related systems, structures, and components during normal plant operation. The turbine building contains steam and power conversion systems components, and support systems and components necessary to support fire protection, SBO, and anticipated transients without scram (ATWS). The turbine building contains certain nonsafety
-related electrical and mechanical components which perform intended functions considered important to safety by providing input signals and actuation devices for the reactor trip and engineered safety features actuation systems and by providing a means for feedwater isolation.
LRA Table 2.4-16 identifies the components subject to an AMR for the turbine building by component type and intended function.
2.4.16.2  Conclusion The staff followed the evaluation methodology discussed in SER Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the 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).
2.4.17  Yard Structures 2.4.17.1  Summary of Technical Information in the Application LRA Section 2.4.17 describes the yard structures which includes the compressed gas storage areas, tank foundations and dikes, pipe support structures, circulating water system piping foundations, turbine crane runway extensions, manholes, handholes and duct banks, miscellaneous yard structures, miscellaneous yard enclosures, transformer foundations, trenches, and yard drainage system.
The purpose of the yard structures are to provide structural support, shelter, and protection for safety-related and nonsafety
-related components and commodities, including components credited for SBO, Fire Protection, and ATWS.
LRA Table 2.4-17 identifies the components subject to an AMR for the yard structures by component type and intended function.
 
Structures and Components Subject to Aging Management Review 2-88 2.4.17.2  Conclusion The staff followed the evaluation methodology discussed in SER Section 2.4 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the staff's review determined whether the applicant failed to identify any SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that the applicant has adequately identified the yard structure SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.5  Scoping and Screening Results:  Electrical and Instrumentation and Controls (I&C) Systems This Section documents the staff's review of the applicant's scoping and screening results for electrical and instrumentation and controls (I&C) systems. Specifically, this Section discusses:
electrical and I&C component commodity groups In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, long-lived systems, structures, or components (SSC) within the scope of license renewal and subject to an AMR (AMR). To verify that the applicant properly implemented its methodology, the staff's review focused on the implementation results. This focus allowed the staff to confirm that there were no omissions of electrical and I&C system components that meet the scoping criteria and are subject to an AMR.
The staff's evaluation of the information in the LRA was the same for all electrical and I&C systems. The objective was to determine whether the applicant has identified, in accordance with 10 CFR 54.4, components and supporting structures for electrical and I&C systems that appear to meet the license renewal scoping criteria. Similarly, the staff evaluated the applicant's screening results to verify that all passive, long-lived components were subject to an AMR in 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 the UFSAR for each electrical and I&C system to determine whether the applicant has omitted from the scope of license renewal components with intended functions delineated under 10 CFR 54.4(a). After its review of the scoping results, the staff evaluated the applicant's screening results. For those SSCs with intended functions, the staff sought to determine whether (1) the functions are performed with moving parts or a change in configuration or properties
, or (2) the SSCs 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 SSCs were subject to an AMR, as required by 10 CFR 54.21(a)(1).
 
Structures and Components Subject to Aging Management Review 2-89 2.5.1  Electrical/I&C Component Commodity 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 includes all plant electrical and I&C components. Evaluation of electrical systems includes electrical and I&C components in mechanical systems. The plant-wide basis 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.
The electrical and I&C components that were identified to be within the scope of license renewal have been grouped by the applicant into component commodity groups. The applicant has applied the screening criteria in 10 CFR 54.21(a)(1)(i)  and 10 CFR 54.21(a)(1)(ii) to this list of component commodity groups to identify those that perform their intended functions without moving parts
, without a change in configuration or properties
, and to remove the component commodity groups that are subject to replacement based on a qualified life or specified time period. LRA Table 2.5.2-1 identifies electrical component commodity group component types and their intended function within the scope of license renewal and subject to an AMR:
cable connections
-metallic parts/ electrical continuity connector contacts for electrical connectors exposed to borated water leakage/ electrical continuity fuse holders/ electrical continuity high voltage insulators/ insulation
-electrical insulated cables and connections/ electrical continuity metal enclosed bus/ electrical continuity, insulation
-electrical, shelter and fire protection switchyard bus and connections/ electrical continuity 2.5.1.2  Staff Evaluation The staff reviewed LRA Section 2.5 and Salem 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).
 
Structures and Components Subject to Aging Management Review 2-90 General Design Criteria 17 of 10 CFR Part 50, Appendix A, requires that electric power from the transmission network to the onsite electric distribution system be supplied by two physically independent circuits to minimize the likelihood of their simultaneous failure. In addition, the staff noted that the guidance provided by letter dated April 1, 2002 (ADAMS Accession No. ML020920464) "Staff Guidance on Scoping of Equipment Relied on to Meet the Requirements of the Station Blackout Rule (10 CFR 50.63) for License Renewal (10 CFR 54.4(a)(3))," and later incorporated in SRP
-LR Section 2.5.2.1.1, states:
For purposes of the license renewal rule, the staff has determined that the plant system portion of the offsite power system that is used to connect the plant to the offsite power source should be included within the scope of the rule. This path typically includes switchyard circuit breakers that connect to the offsite system power transformers (startup transformers), the transformers themselves, the intervening overhead or underground circuits between circuit breaker and transformer and transformer and onsite electrical system, and the associated control circuits and structures. Ensuring that the appropriate offsite power system long
-lived passive SSCs that are part of this circuit path are subject to an AMR will assure that the bases underlying the SBO requirements are maintained over the period of extended license.
The applicant included the complete circuits between the onsite circuits
, up to and including
, switchyard breakers (including the associated controls and structures) within the scope of license renewal. Figure 2.1
-2, "Salem Offsite Power for SBO," indicates the SBO recovery path and electrical distribution systems. Section 2.5.1 of the LRA states that the scoping boundary consists of six 500 kV switchyard circuit breakers (10X, 11X, 20X, 21X, 30X, and 31X). Consequently, the staff concludes that the scoping is consistent with the guidance issued April 1, 2002 , and later incorporated it in SRP
-LR Section 2.5.2.1.1.
The applicant has determined that cable tie
-wraps are not within the scope of license renewal and are subject to an AMR. In the LRA, the applicant stated that cable tie
-wraps are used to bundle wires and cables together to maintain the cable runs neat and orderly. The cable tie-wraps are not credited for maintaining cable ampacity, ensuring maintenance of cable minimum bending radius or maintaining cables within vertical raceways. Furthermore, the applicant is not crediting the use of cable tie
-wraps in the seismic qualification of cable trays. Based on the review of this information and the UFSAR, the staff finds the applicant's exclusion of cable tie
-wraps from the SSC's subject to an AMR, acceptable.
The transmission conductors and connections commodity group consists of a portion of the circuits that supply power from the main generator to the electric power grid, as stated in Section 2.5.2.3 of the LRA. Since these components are not in the SBO recovery path and do not perform any intended functions for license renewal, the staff finds that transmission conductors and connections are not subject to an AMR.
2.5.1.3  Conclusion The staff reviewed the evaluation methodology discussed in Section 2.5 and reviewed the LRA and UFSAR to determine whether the applicant failed to identify any SSCs within the scope of license renewal. The staff has found no such omissions. In addition, the staff's review determined whether the applicant failed to identify any components subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that there is reasonable assurance that the applicant has adequately identified the electrical and instrumentation and controls 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).
 
Structures and Components Subject to Aging Management Review 2-91 2.6  Conclusion for Scoping and Screening The staff reviewed the information in LRA Section 2, "Scoping and Screening Methodology for Identifying Structures and Components Subject to Aging Management Review, and Implementation Results.
"  The staff finds that the applicant's scoping and screening methodology is consistent with the requirements of 10 CFR 54.21(a)(1), and the staff's position on the treatment of safety
-related and no nsafety-related SSCs within the scope of license renewal and the SCs requiring an AMR are consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1).
On the basis of its review, the staff concludes that the applicant has adequately identified those systems, structures and components that are within the scope of license renewal as required by 10 CFR 54.4(a), and those structures and components that are subject to an AMR as required by 10 CFR 54.21(a)(1).
With regard to these matters, the staff concludes that the activities authorized by the renewed license will continue to be conducted in accordance with the CLB, and any changes made to the CLB, to comply with 10 CFR 54.21(a)(1), are in accordance with the NRC's regulations.
 
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 Salem Nuclear Generating Station Units 1 and 2 (Salem), by the staff of the U.S. Nuclear Regulatory Commission (NRC or the staff).
In Appendix B of its license renewal application (LRA), PSEG Nuclear, LLC (PSEG or the applicant) described the 48 AMPs it relies on to manage or monitor the aging of passive and long-lived structures and components (SCs).
In LRA Section 3, the applicant provided the results of the AMRs for those SCs identified in LRA Section 2 as within the scope of license renewal and subject to an AMR.
3.0  Applicant's Use of the Generic Aging Lessons Learned Report In preparing its LRA, the applicant credited NUREG
-1801, "Generic Aging Lessons Learned (GALL) Report," Revision 1, dated September 2005. The GALL Report contains the staff's generic evaluation of the existing plant programs and documents the technical basis for determining where existing programs are adequate without modification and where existing programs should be augmented for the period of extended operation. The evaluation results documented in the GALL Report indicate that many of the existing programs are adequate to manage the aging effects for particular SCs for license renewal without change. The GALL Report also contains recommendations on specific areas for which existing programs should be augmented for license renewal. An applicant may reference the GALL Report in its LRA to demonstrate that the programs at its facility correspond to those reviewed and approved in the GALL Report. The purpose of the GALL Report is to provide the staff with a summary of staff
-approved AMPs to manage or monitor the aging of SCs subject to an AMR. If an applicant commits to implementing these staff
-approved AMPs, the time, effort, and resources used to review an applicant's LRA will be greatly reduced, thereby improving the efficiency and effectiveness of the license renewal review process. The GALL Report also serves as a reference for applicants and staff reviewers to quickly identify those AMPs and activities that the staff has determined will adequately manage or monitor aging during the period of extended operation.
The GALL Report identifies:  (1) systems, structures, and components (SSCs); (2) SC materials; (3) environments to which the SCs are exposed; (4) the aging effects associated with the materials and environments; (5) the AMPs credited with managing or monitoring the aging effects; and (6) recommendations for further applicant evaluations of aging management for certain component type
: s. The staff performed its review in accordance with the requirements of Title 10, Part 54 of the Code of Federal Regulations (10 CFR Part 54), "Requirements for Renewal of Operating Licenses for Nuclear Power Plants"; the guidance provided in NUREG
-1800, "Standard Review Aging Management Review Results 3-2 Plan for Review of License Renewal Applications for Nuclear Power Plant" (SRP
-LR), Revision 1, dated September 2005; and the guidance provided in the GALL Report.
In addition to its review of the LRA, the staff conducted an onsite audit of selected AMRs and associated AMPs during the weeks of February 8 and February 19 , 2010 as described in the "Audit Report Regarding the Salem Nuclear Generating Station, Units 1 and 2, License Renewal Application," dated August 18, 2010. The onsite audits and reviews are designed to maximize the efficiency of the staff's LRA review. The applicant can respond to questions, the staff can readily evaluate the applicant's responses, the need for formal correspondence between the staff and the applicant is reduced, and the result is an improvement in review efficiency.
3.0.1  Format of the License Renewal Application The applicant submitted an application that followed the standard LRA format, as determined by the NRC and the Nuclear Energy Institute (NEI) by letter dated August 18, 2009. This LRA format incorporates lessons learned from the staff's reviews of previous LRAs which used a format developed from information gained during a staff
-NEI demonstration project conducted to evaluate the use of the GALL Report in the LRA review process.
The organization of LRA Section 3 parallels Chapter 3 of the SRP
-LR. The AMR results information in LRA Section 3 is presented in the following two table types:
  (1) Table 3.x.1-where "3" indicates the LRA Section number, "x" indicates the subSection number from the GALL Report, and "1" indicates that this is the first table type in LRA Section 3.  (2) Table 3.x.2-y-where "3" indicates the LRA Section number, "x" indicates the subSection number from the GALL Report, "2" indicates that this is the second table type in LRA Section 3, and "y" indicates the system table number.
The content s of the previous applications and the Salem application are essentially the same. The intent of the format used for the Salem LRA was to modify the tables in Chapter 3 to provide additional information that would assist the staff in its review. In each Table 1, the applicant summarized the portions of the application that it considered to be consistent with the GALL Report. In each Table 2, the applicant identified the linkage between the scoping and screening results in Chapter 2 and the AMRs in LRA Chapter 3. 3.0.1.1  Overview of Table 1s Each Table 3.x.1 (Table 1) provides a summary comparison of how the facility aligns with the corresponding tables of the GALL Report. The table is essentially the same as Tables 1 through 6 provided in the GALL Report, Volume 1, except that the "Type" column has been replaced by an "Item Number" column and the "Related Generic Item" and "Unique Item" columns have been replaced by a "Discussion" column. The "Discussion" column is used by the applicant to provide clarifying and amplifying information.
The following are some examples of information that might be contained within this column:
 
Aging Management Review Results 3-3  further evaluation recommended
-information or reference to where that information is located  the name of a plant
-specific program exceptions to the GALL Report assumptions  discussion of how the line is consistent with the corresponding line item in the GALL Report when this consistency may not be obvious  discussion of how the item is different from the corresponding line item in the GALL Report (e.g., when an exception is taken to a GALL Report AMP)
The format of Table 1 allows the staff to align a specific Table 1 row with the corresponding GALL Report table row so that the consistency can be efficiently checked. 3.0.1.2  Overview of Table 2s Each Table 3.x.2-y (Table 2) provides the detailed results of the AMRs for those components identified in LRA Section 2 as subject to an AMR. The LRA contains a Table 2 for each of the systems or components within a system grouping (e.g., reactor coolant systems, engineer ed safety features, auxiliary systems, etc.). For example, the engineered safety features (ESF) group contains tables specific to the containment spray system, residual heat removal system, and safety injection system. Each Table 2 consists of the following nine columns
:  (1) Component Type
-The first column identifies the component types from LRA Section 2 subject to an AMR. The component types are listed in alphabetical order.
  (2) Intended Function
-The second column contains the license renewal intended functions for the listed component types. Definitions of intended functions are contained in LRA Table 2.1-1.  (3) Material-The third column lists the particular materials of construction for the component type.  (4) Environment
-The fourth column lists the environment to which the component types are exposed. Internal and external service environments are indicated
; a list of these environments is provided in LRA Tables 3.0-1 and 3.0-2.  (5) Aging Effect Requiring Management
-The fifth column lists aging effects requiring management (AERMs). As part of the AMR process, the applicant determined any AERMs for each combination of material and environment.
  (6) Aging Management Programs
-The sixth column lists the AMPs that the applicant used to manage the identified aging effects.
  (7) NUREG-1801 Volume 2 Item
- The seventh column lists the GALL Report item(s) that the applicant identified as similar to the AMR results in the LRA. The applicant compared each combination of component type, material, environment, AERM, and AMP in Table 2 of the LRA to the items in the GALL Report. If there were no corresponding items in the GALL Report, the applicant left the column blank. In this Aging Management Review Results 3-4 way, the applicant identified the AMR results in the LRA tables that corresponded to the items in the GALL Report tables.
  (8) Table 1 Item-The eighth column lists the corresponding summary item number from Table 1. If the applicant identifies AMR results in Table 2 that are consistent with the GALL Report, then the associated Table 3.x.1 line summary item number should be listed in Table
: 2. If there is no corresponding item in the GALL Report, then column eight is left blank. That way, the information from the two tables can be correlated.
  (9) Notes-The ninth column lists the corresponding notes that the applicant used to identify how the information in Table 2 aligns with the information in the GALL Report. The notes identified by letters were developed by an NEI working group and will be used in future LRAs. Any plant
-specific notes are identified by a number and provide additional information concerning the consistency of the line item with the GALL Report.
3.0.2  Staff's Review Process The staff conducted the following three types of evaluations of the AMRs and associated AMPs:
  (1) For items that the applicant stated were consistent with the GALL Report, the staff conducted either an audit or a technical review to determine consistency.
  (2) For items that the applicant stated were consistent with the GALL Report with exceptions and/or enhancements, the staff conducted either an audit or a technical review of the item to determine consistency with the GALL Report. In addition, the staff conducted either an audit or a technical review of the applicant's technical justification for the exceptions and the adequacy of the enhancements.
  (3) For other items, the staff conducted a technical review pursuant to 10 CFR 54.21(a)(3).
These audits and technical reviews determine whether the effects of aging on SCs can be adequately managed so that the intended functions can be maintained consistent with the plant's current licensing basis (CLB) for the period of extended operation, as required by 10 CFR Part 54. 3.0.2.1  Review of AMPs For those AMPs for which the applicant had claimed consistency with the GALL Report AMPs, the staff conducted either an audit or a technical review to confirm that the applicant's AMPs were consistent with the GALL Report. For each AMP that had one or more deviations, the staff evaluated each deviation to determine whether the deviation was acceptable and whether the AMP, as modified, would adequately manage the aging effect(s) for which it was credited. For AMPs that were not addressed in the GALL Report, the staff performed a full review to determine their adequacy. The staff evaluated the AMPs against the following 10 program elements defined in SRP
-LR Appendix A, which follow.
  (1) Scope of the Program:  The scope of the program should include the specific SCs subject to an AMR for license renewal.
  (2) Preventive Actions:  Preventive actions should prevent or mitigate aging degradation.
 
Aging Management Review Results 3-5  (3) Parameters Monitored or Inspected:  Parameters monitored or inspected should be linked to the degradation of the particular structure or component
's intended function(s).
  (4) Detection of Aging Effects:  Detection of aging effects including such aspects as method or technique (i.e., visual, volumetric, surface inspection), frequency, sample size, data collection, and timing of new/one
-time inspections should occur before there is a loss of structure or component intended function(s).
  (5) Monitoring and Trending:  Monitoring and trending should provide predictability of the extent of degradation, as well as timely corrective or mitigative actions.
  (6) Acceptance Criteria:  Acceptance criteria, against which the need for corrective actio n
will be evaluated, should ensure that the structure or component intended function(s) are maintained under all CLB design conditions during the period of extended operation.
  (7) Corrective Actions:  Corrective actions, including root cause determination and prevention of recurrence, should be timely.
  (8) Confirmation Process:  Confirmation process should ensure that preventive actions are adequate and that appropriate and effective corrective actions have been completed.
  (9) Administrative Controls:  Administrative controls should provide a formal review and approval process.
  (10) Operating Experience:  Operating experience of the AMP, including past corrective actions resulting in program enhancements or additional programs, should provide objective evidence to support the conclusion that the effects of aging will be adequately managed so that the SC intended functions will be maintained during the period of extended operation.
Details of the staff's audit evaluation of program elements (1) through (6) and (10) are documented in the AMP Audit Report and summarized in SER Section 3.0.3. The staff reviewed the applicant's corrective action program and documented its evaluations in SER Section 3.0.4. The staff's evaluation of the corrective action program included assessments of the following program elements:  (7) "corrective actions," (8) "confirmation process," and (9) "administrative controls."
The staff reviewed the information on the operating experience program element and documented its evaluation in SER Section 3.0.3. 3.0.2.2  Review of AMR Results Table 2 contains information concerning whether the AMRs align with the AMRs identified in the GALL Report. For a given AMR in Table 2, the staff reviewed the intended function, material, environment, AERM, and AMP combination for a particular component type within a system. The AMRs that correlate between a combination in Table 2 and a combination in the GALL Report were identified by a referenced item number in column seven, "NUREG
-1801 Volume 2 Line Item."  The staff also conducted onsite audits to verify the correlation. A blank column seven indicates that the applicant was unable to locate an appropriate corresponding combination in the GALL Report. The staff conducted a technical review of these combinations Aging Management Review Results 3-6 not consistent with the GALL Report. The next column, "Table 1 Item," provides a reference number that indicates the corresponding row in Table
: 1. 3.0.2.3  UFSAR Supplement Consistent with the SRP
-LR, for the AMRs and associated AMPs that it reviewed, the staff also reviewed the UFSAR supplement that summarizes the applicant's programs and activities for managing the effects of aging for the period of extended operation, as required by 10 CFR 54.21(d). 3.0.2.4  Documentation and Documents Reviewed In performing its review, the staff used the LRA, LRA supplements, SRP
-LR, GALL Report and RAI responses.
Also, during the onsite audit, the staff examined the applicant's justifications, as documented in the Audit Summary Report, to verify that the applicant's activities and programs will adequately manage the effects of aging on SCs. The staff also conducted detailed discussions and interviews with the applicant's license renewal project personnel and others with technical expertise relevant to aging management.
3.0.3  Aging Management Programs SER Table 3.0.3-1 below presents the AMPs credited by the applicant and described in LRA Appendix B. The table also indicates the GALL Report AMP that the applicant claimed its AMP was consistent with, if applicable, and the SSCs for managing or monitoring aging. The Section of the SER, in which the staff's evaluation of the program is documented, is also provided.
Aging Management Review Results 3-7 Table 3.0.3-1  Salem Units 1 and 2 Aging Management Programs Applicant Aging Management Program LRA Sections New or Existing Program Applicant Comparison to the GALL Report GALL Report Aging Management Programs  SER Section ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD A.2.1.1 B.2.1.1 Existing Consistent XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD" 3.0.3.1.1 Water Chemistry A.2.1.2 B.2.1.2 Existing Consistent XI.M2, "Water Chemistry" 3.0.3.1.2 Reactor Head Closure Studs A.2.1.3 B.2.1.3 Existing Consistent XI.M3, "Reactor Head Closure Studs" 3.0.3.1.3 Boric Acid Corrosion A.2.1.4 B.2.1.4 Existing Consistent XI.M10, "Boric Acid Corrosion 3.0.3.1.4 Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors  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 Reactors" 3.0.3.1.5 Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) A.2.1.6 B.2.1.6 New Consistent XI.M12, "Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)" 3.0.3.1.6 PWR Vessel Internals A.2.1.7 B.2.1.7 New Consistent XI.M16, "PWR Vessel Internals" 3.0.3.1.7 Flow-Accelerated Corrosion A.2.1.8 B.2.1.8 Existing Consistent with Exception XI.M17, "Flow-Accelerated Corrosion" 3.0.3.2.1 Bolting Integrity A.2.1.9 B.2.1.9 Existing Consistent with Exception and Enhancement XI.M18, "Bolting Integrity" 3.0.3.2.2 Steam Generator Tube Integrity A.2.1.10 B.2.1.10 Existing Consistent XI.M19, "Steam Generator Tube Integrity" 3.0.3.1.8 Open-Cycle Cooling Water System A.2.1.11 B.2.1.11 Existing Consistent XI.M20, "Open
-Cycle Cooling Water System" 3.0.3.1.9 Closed-Cycle Cooling Water System A.2.1.12 B.2.1.12 Existing Consistent with Exception and Enhancements XI.M21, "Closed-Cycle Cooling Water System" 3.0.3.2.3 Aging Management Review Results 3-8 Applicant Aging Management Program LRA Sections New or Existing Program Applicant Comparison to the GALL Report GALL Report Aging Management Programs  SER Section Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems A.2.1.13 B.2.1.13 Existing Consistent with Enhancements XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems" 3.0.3.2.4 Compressed Air Monitoring A.2.1.14 B.2.1.14 Existing Consistent XI.M24, "Compressed Air Monitoring" 3.0.3.1.10 Fire Protection A.2.1.15 B.2.1.15 Existing Consistent with Exception and Enhancements XI.M26, "Fire Protection" 3.0.3.2.5 Fire Water System A.2.1.16 B.2.1.16 Existing Consistent with Enhancements XI.M27, "Fire Water System" 3.0.3.2.6 Aboveground Steel Tanks  A.2.1.17 B.2.1.17 Existing Consistent with Enhancements XI.M29, "Aboveground Steel Tanks" 3.0.3.2.7 Fuel Oil Chemistry A.2.1.18 B.2.1.18 Existing Consistent with Exceptions and Enhancements XI.M30, "Fuel Oil Chemistry" 3.0.3.2.8 Reactor Vessel Surveillance A.2.1.19 B.2.1.19 Existing Consistent with Enhancements XI.M31, "Reactor Vessel Surveillance" 3.0.3.2.9 One-Time Inspection A.2.1.20 B.2.1.20 New Consistent XI.M32, "One
-Time Inspection" 3.0.3.1.11 Selective Leaching of Materials A.2.1.21 B.2.1.21 New Consistent XI.M33, "Selective Leaching of Materials" 3.0.3.1.12 Buried Piping Inspection A.2.1.22 B.2.1.22 Existing Consistent with Enhancement XI.M34, "Buried Piping and Tanks Inspection" 3.0.3.2.10 One-Time Inspection of ASME Code Class 1 Small-Bore Piping 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" 3.0.3.2.11 External Surfaces Monitoring A.2.1.24 B.2.1.24 New Consistent XI.M36, "External Surfaces Monitoring" 3.0.3.1.13 Flux Thimble Tube Inspection A.2.1.25 B.2.1.25 New Consistent XI.M37, "Flux Thimble Tube Inspection" 3.0.3.1.14 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components A.2.1.26 B.2.1.26 New Consistent XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" 3.0.3.1.15 Lubricating Oil Analysis A.2.1.27 B.2.1.27 Existing Consistent with Exception XI.M39, "Lubricating Oil Analysis" 3.0.3.2.12
 
Aging Management Review Results 3-9 Applicant Aging Management Program LRA Sections New or Existing Program Applicant Comparison to the GALL Report GALL Report Aging Management Programs  SER Section ASME Section XI, SubSection IWE A.2.1.28 B.2.1.28 Existing Consistent with Enhancement XI.S1, "ASME Section XI, SubSection IWE" 3.0.3.2.13 ASME Section XI, SubSection IWL A.2.1.29 B.2.1.29 Existing Consistent XI.S2, "ASME Section XI, SubSection IWL" 3.0.3.1.16 ASME Section XI, SubSection IWF A.2.1.30 B.2.1.30 Existing Consistent XI.S3, "ASME Section XI, SubSection IWF" 3.0.3.1.17 10 CFR 50, Appendix J A.2.1.31 B.2.1.31 Existing Consistent XI.S4, "10 CFR 50 Appendix J" 3.0.3.1.18 Masonry Wall Program A.2.1.32 B.2.1.32 Existing Consistent with Enhancements XI.S5, "Masonry Wall Program" 3.0.3.2.14 Structures Monitoring Program A.2.1.33 B.2.1.33 Existing Consistent with Enhancements XI.S6, "Structures Monitoring Program" 3.0.3.2.15 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants A.2.1.34 B.2.1.34 Existing Consistent with Enhancements XI.S7, "RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants" 3.0.3.2.16 Protective Coating Monitoring and Maintenance Program A.2.1.35 B.2.1.35 Existing Consistent XI.S8, "Protective Coating Monitoring and Maintenance Program" 3.0.3.1.19 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements A.2.1.36 B.2.1.36 New Consistent XI.E1, "Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements" 3.0.3.1.20 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits A.2.1.37 B.2.1.37 New Consistent XI.E2, "Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits" 3.0.3.1.21 Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements A.2.1.38 B.2.1.38 New Consistent XI.E3, "Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements" 3.0.3.1.22
 
Aging Management Review Results 3-10 Applicant Aging Management Program LRA Sections New or Existing Program Applicant Comparison to the GALL Report GALL Report Aging Management Programs  SER Section Metal Enclosed Bus A.2.1.39 B.2.1.39 New Consistent XI.E4, "Metal Enclosed Bus" 3.0.3.1.23 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements A.2.1.40 B.2.1.40 New Consistent with Exception XI.E6, "Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements" 3.0.3.2.17 High Voltage Insulators A.2.2.1 B.2.2.1 New Plant-Specific N/A 3.0.3.3.1 Periodic Inspection A.2.2.2 B.2.2.2 New Plant-Specific N/A 3.0.3.3.2 Aboveground Non-Steel Tanks A.2.2.3 B.2.2.3 New Plant-Specific N/A 3.0.3.3.3 Buried Non
-Steel Piping Inspection A.2.2.4 B.2.2.4 Existing Plant-Specific N/A 3.0.3.3.4 Boral Monitoring Program A.2.2.5 B.2.2.5 Existing Plant-Specific N/A 3.0.3.3.5 Nickel Alloy Aging Management A.2.2.6 B.2.2.6 Existing Plant-Specific N/A 3.0.3.3.6 Metal Fatigue of Reactor Coolant Pressure Boundary A.3.1.1 B.3.1.1 Existing Consistent with Enhancements X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary" 3.0.3.2.18 Environmental Qualification (EQ) of Electric Components A.3.1.2 B.3.1.2 Existing Consistent X.E1, "Environmental Qualification (EQ) of Electric Components" 3.0.3.1.24 3.0.3.1  AMPs That Are Consistent with the GALL Report In LRA Appendix B, the applicant identified the following AMPs as being consistent with the GALL Report:
ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Water Chemistry Reactor Head Closure Studs Boric Acid Corrosion Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)
PWR Vessel Internals
 
Aging Management Review Results 3-11  Steam Generator Tube Integrity Open-Cycle Cooling Water System Compressed Air Monitoring One-Time Inspection Selective Leaching of Materials External Surfaces Monitoring Flux Thimble Tube Inspection Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components ASME Section XI, SubSection IWL  ASME Section XI, SubSection IWF  10 CFR 50 , Appendix J  Protective Coating Monitoring and Maintenance Program Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Metal Enclosed Bus Environmental Qualification (EQ) of Electric Components 3.0.3.1.1  ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Summary of Technical Information in the Application. LRA Section B.2.1.1 describes the existing ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program as consistent with GALL AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD."  The applicant stated that the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program includes inspections performed to manage cracking, loss of fracture toughness, and loss of material in Class 1, 2, and 3 piping and components exposed to air, reactor coolant, steam, treated water, and treated borated water environments within the scope of license renewal. The applicant stated that the program provides for periodic visual, surface, volumetric examination , and for leakage testing of pressure
-retaining piping and components including welds, pump casings, steam generator components, nozzles and safe ends, valve bodies, integral attachments, and pressure-retaining bolting and that the program Aging Management Review Results 3-12 consists of condition monitoring activities that detect degradation of components before loss of intended function.
The applicant stated that its current ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program is based on the 1998 Edition through the 2000 Addenda of American Society of Mechanical Engineers (ASME) Code Section XI and that its program is updated each successive 120
-month inspection interval to comply with the requirements of the latest, edition of the ASME Code, as specified in 10 CFR 50.55a, 12 months before the start of the inspection interval. 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 with the corresponding elements of GALL AMP XI.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 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).
The staff noted that the applicant is currently in its third, 10
-year inservice inspection (ISI) interval and that the current ISI interval does not continue into the period of extended operation.
The staff also noted that during the current interval, the applicant's ISI program includes a risk-informed inservice inspection (RI
-ISI) methodology that has been approved for the current interval in accordance with the requirements of 10 CFR 50.55a. The staff further noted that in LRA Section B.2.1.1, the applicant stated that its ISI program uses an alternative method to determine the inspection locations, inspection frequency, and inspection techniques for Class 1 Category B-F and B-J, and Class 2 Category C
-F-1 and C-F-2 welds. It was not clear to the staff whether the discussion of alternative inspection methods in the LRA is applicable only to the current inspection interval or whether the discussion also applies to the period of extended operation. In its letter of July 12, 2010 RAI B.2.1.1-01, the staff requested that the applicant explain why RI
-ISI and other alternatives to the requirements of ASME Code Section XI, Subsections IWB, IWC, and IWD are discussed in the LRA's "program description" for the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program.
The applicant's August 10, 2010 stated that RI
-ISI and other alternatives to the ASME Code Section XI requirements were discussed in the LRA because they are contained in the applicant's existing ISI program plan for the third 10
-year inspection interval, which was used to evaluate the ISI program against the recommendations in GALL AMP XI.M1. The applicant stated that it recognizes that the license renewal process does not review and approve future station ISI program plans, including RI
-ISI and other alternatives to the ASME Code Section XI requirements. The applicant further stated that at the end of the current 10
-year ISI interval, it will be required to submit an update to its ISI program plan for staff review in accordance with the requirements of 10 CFR 50.55a. Based on its audit and review of the applicant's response to RAI B.2.1.1-01, the staff finds that elements one through six of the applicant's ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program are consistent with the corresponding program elements of GALL AMP XI.M1 and, therefore, acceptable.
 
Aging Management Review Results 3-13 Operating Experience. LRA Section B.2.1.1 summarizes operating experience related to the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. The applicant described detection of a weld flaw using dye penetrant examination at Unit 2 in 2000 and identification of weld indications in the 2005 baseline draft report for Salem 2.
For the flaw detected in 2000, the applicant stated that documentation of the flaw was entered into the site's corrective action program, additional ultrasonic examinations were performed, and the indication and expansion results were evaluated in accordance with ASME Code Section XI criteria and found to be acceptable. For the baseline indications reported in 2005, the applicant stated that the indications were determined most likely to be weld fabrication indications caused by embedded slag inclusions and oxides that occurred along the weld fusion line. The applicant further stated that corrective actions included an independent structural evaluation related to the indications and improving the workmanship in removing slag from the manufacturing of the Salem Unit 1 replacement reactor vessel head. The applicant stated that these examples demonstrate the program effectively identifies degradation prior to failure and that it provides appropriate guidance for expanded examination, evaluation, repair, or replacement when degradation is found.
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. 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 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 of SRP
-LR Section A.1.2.3.10 and, therefore, the staff finds it acceptable.
UFSAR Supplement. LRA Section A.2.1.1 provides the UFSAR supplement for the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. The staff reviewed this UFSAR supplement description of the program and notes that it conforms to the recommended description for this type of program as described in SRP
-LR Table 3.1-2. The staff also notes that the applicant committed (Commitment No. 1) to ongoing implementation of the existing ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program for managing aging of applicable components during the period of extended operati on. The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program, the RAI responses, and the audit, 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 Aging Management Review Results 3-14 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 Summary of Technical Information in the Application. LRA Section B.2.1.2 describes the existing Water Chemistry Program as consistent with GALL AMP XI.M2, "Water Chemistry."  The applicant stated that the Water Chemistry Program monitors and controls the chemical environment of the primary and secondary systems. The applicant credited the program for the management of the aging effects of cracking, loss of material, reduction of neutron
-absorbing capacity and reduction of heat transfer, and the mitigation of stress
-corrosion cracking (SCC). The applicant also stated that the primary water portion of the program is consistent with Electric Power Research Institute (EPRI) 1014986, "PWR Primary Water Chemistry Guidelines," Revision 6, and that the secondary water portion of the program is consistent with EPRI 1008224, "PWR Secondary Water Chemistry Guidelines," Revision 6. The applicant further stated that the Water Chemistry Program includes periodic sampling of primary and secondary water for detrimental contaminants specified in EPRI water chemistry guidelines. The applicant identified the reactor vessel, reactor internals, piping, piping elements and piping components, heat exchangers, and tanks as the major components of the primary 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 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 AMP XI.M2. As discussed in the Audit Report, the staff confirmed that these elements are consistent with the corresponding elements of GALL AMP XI.M2. Based on its audit, the staff finds that elements one through six of the applicant's Water Chemistry Program are consistent with the corresponding program elements of GALL AMP XI.M2 and, therefore, acceptable.
Operating Experience. LRA Section B.2.1.2 summarizes operating experience related to the Water Chemistry Program. The applicant stated that it experienced an unexpected reactor coolant system (RCS) dissolved oxygen (DO) transient after a startup following a steam generator replacement and that the cause of the DO transient was that sufficient air was left in the RCS to create a hydraulic lock that prevented back flow through the steam generator U-tubes. As a result of this DO transient, the applicant modified its vacuum refill procedure to prevent a recurrence of this event. The applicant stated that subsequent startups using vacuum refill have resulted in minimal DO in the RCS. The applicant further stated that this operating experience is an example of how the Water Chemistry Program is able to identify unexpected behaviors and modify system operation to prevent a recurrence of initiating events.
The applicant stated that in 2008, it identified an increasing trend in sodium concentrations, which remained below acceptable limits. The applicant also stated that it performed grab samples to confirm the online monitor indications and that it identified the cause of the increase in sodium as a small river water leak into the steam generator blowdown (SGBD) condenser. The applicant further stated that the SGBD condenser was taken off line as part of a troubleshooting plan and that sodium levels dropped to normal values
, and that this operating experience demonstrate s that the Water Chemistry Program was able to detect, identify, and correct issues based on relatively minor excursions in water chemistry.
 
Aging Management Review Results 3-15 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. 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 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 and, 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 notes 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 No. 2) to ongoing implementation of the existing Water Chemistry Program for managing aging of applicable components during the period of extended operation.
The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's Water Chemistry 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). 3.0.3.1.3  Reactor Head Closure Studs Summary of Technical Information in the Application. LRA Section B.2.1.3 describes the existing Reactor Head Closure Studs Program as consistent with GALL AMP XI.M3, "Reactor Head Closure Studs."  The applicant stated that the program provides for ASME Code Section XI inspections of reactor head closure studs, nuts, and washers for cracking, loss of material, loss of fracture toughness, and coolant leakage from reactor vessel closure stud bolting in an air environment. The applicant stated that the Reactor Head Closure Studs Program is a condition based monitoring program that effectively monitors and detects the applicable aging effects and that the frequency of monitoring is adequate to prevent significant degradation. The applicant further stated that the program is based on examination and inspection requirements specified in the ASME Code Section XI, 1998 Edition, including 2000 Addenda, and preventive measures described in NRC Regulatory Guide (RG) 1.65, "Materials and Inspection for Reactor Vessel Closure Studs."  The applicant also stated that:  (1) the program uses visual and volumetric examinations in accordance with ASME Code Aging Management Review Results 3-16 Section XI, (2) the applicable edition of the ASME Code does not require surface examinations of the studs, and (3) surface examinations of the reactor head closure studs are not performed. The applicant stated that the extent and schedule for examining and testing the reactor head closure studs, nuts, and washers are as specified in ASME Code Section XI, Table IWB
-2500-1 for Examination Category B
-G-1 components, "Pressure Retaining Bolting Greater than 2 Inches in Diameter."
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 evaluate
: d. The staff compared elements one through six of the applicant's program to the corresponding elements of GALL 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 AMP XI.M3, with the exception of the "detection of aging effects" program element. For this program element, the staff determined the need for additional clarification, which resulted in the issuance of an RAI.
In GALL AMP XI.M3, the "detection of aging effects" program element states that Examination Category B
-G-1 for pressure
-retaining bolting greater than 2 inches in diameter in reactor vessels specifies both a surface and a volumetric examination of the studs when they are removed from the reactor vessel flange. In its review of the applicant's "detection of aging effects" program element, the staff noted that the applicant performs a volumetric (not volumetric and surface) examination of reactor head closure studs when they are removed from the reactor vessel flange. The staff also noted that in the "Program Description" subSection of LRA Section B.2.1.3, the applicant stated that the program provides inspections of reactor head closure studs, nuts, and washers for cracking, loss of material, loss of fracture toughness, and coolant leakage from reactor vessel closure stud bolting. The staff further noted that loss of fracture toughness is not addressed as an aging effect in GALL AMP XI.M3.
In its June 10, 2010 RAI B.2.1.3-01, the staff requested that the applicant explain why implementation of only volumetric examinations, rather than volumetric and surface examinations, for removed closure studs was not identified as an exception to the recommendations in the GALL Report and justify how the use of only volumetric inspections for these components will provide adequate detection of aging effects during the period of extended operation.
The staff also requested that the applicant clarify why the loss of fracture toughness is listed as an aging effect managed by the Reactor Head Closure Studs Program.
The applicant's July 8, 2010 response stated that the GALL Report program description states that the ISI requirements are in conformance with the 2001 Edition of the ASME Code Section XI, through the 2003 Addenda. The applicant also stated that the 2001 Edition of the ASME Code Section XI, through the 2003 Addenda, does not require surface examinations of the reactor head closure studs when removed. The applicant further stated that similarly, the Salem Units 1 and 2 ISI program plans, which incorporate the requirements of the ASME Code Section XI 1998 Edition through 2000 Addenda, also do not require surface examinations of the reactor head closure studs when removed, but instead allow either a volumetric or a surface examination. The applicant stated that Salem will continue to satisfy the examination requirements of ASME Code Section XI, Table IWB 2500
-1 for the reactor head closure studs, in place and removed. In addition, the applicant indicated that the volumetric examination (only) of the reactor head closure studs when removed is adequate because such an examination is Aging Management Review Results 3-17 consistent both with applicable ASME Code Section XI requirements and with alternate inspection requirements described in RG 1.65, "Materials and Inspections for Reactor Vessel Closure Studs," Revision 1, dated April 2010. The applicant also stated that LRA Appendix B, Section B.2.1.3 inadvertently states that a loss of fracture toughness is an aging effect managed by the Reactor Head Closure Studs Program. The applicant revised LRA Section B.2.1.3 is to delete the reference to the loss of fracture toughness as an aging effect managed by the Reactor Head Closure Studs Program.
In its review, the staff finds the applicant's change to LRA Section B.2.1.3 acceptable because it clarified that loss of fracture toughness is not an aging effect and, as revised, the aging effects managed by the Reactor Head Closure Studs Program are consistent with the GALL Report.
The staff also finds the applicant's justification for using only volumetric examinations acceptable because the applicable editions and addenda of the ASME Code Section XI allow  surface or volumetric examinations, and the staff finds that volumetric examinations, alone, are adequate to detect cracking as documented in the latest revision of RG 1.65. On this basis, the staff finds that the applicant's response resolves all issues described in RAI B.2.1.3-01. Based on its audit and review of the applicant's response to RAI B.2.1.3-01, the staff finds that elements one through six of the applicant's Reactor Head Closure Studs Program are consistent with the corresponding program elements of GALL AMP XI.M3 and, therefore, acceptable.
Operating Experience. LRA Section B.2.1.3 summarizes operating experience related to the Reactor Head Closure Studs Program. The applicant stated that its Reactor Head Closure Studs Program has provisions regarding inspection techniques and evaluation, material specifications, corrosion prevention, and other aspects of reactor pressure vessel (RPV) head stud cracking. In the LRA, the applicant provided several examples of its operating experience. For Salem Unit 1, the applicant stated that the Reactor Head Closure Studs Program performed ultrasonic testing (UT) and visual testing (VT
-1) examinations of selected reactor head closure studs, nuts, and washers during the fall 2002, fall 2005, and fall 2008 refueling outages with no recordable indications found. For Salem Unit 2, the applicant stated that the Reactor Head Closure Studs Program performed UT and VT
-1 examinations of selected reactor head closure studs, nuts, and washers during the spring 2005, fall 2006, and spring 2008 refueling outages with no recordable indications found. The applicant also stated that the operating experience of the Reactor Head Closure Studs Program shows there are no signs of age
-related degradation and that since no age
-related degraded conditions have existed, no investigations and corrective actions have been required. The applicant further stated that historically, inspections have found the reactor studs, nuts, and washers to be in satisfactory condition and that no studs, nuts, or washers have ever been replaced or repaired as a result of age
-related conditions.
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
-specific 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.
 
Aging Management Review Results 3-18 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 of SRP
-LR Section A.1.2.3.10 and, 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 notes 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 in LRA Section A.5, the applicant adequately committed (Commitment No. 3) to ongoing implementation of the existing Reactor Head Closure Studs Program for managing the aging effects of applicable components during the period of extended operation.
The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's Reactor Head Closure Studs 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). 3.0.3.1.4  Boric Acid Corrosion Summary of Technical Information in the Application. LRA Section B.2.1.4 describes the existing Boric Acid Corrosion Program as consistent with the program elements in GALL AMP XI.M10, "Boric Acid Corrosion."  The applicant stated that the program identifies, inspects, examines, and evaluates leakage, initiates corrective actions, and relies, in part, on implementation of the recommendations provided in NRC Generic Letter (GL) 88-05, "Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR Plants."  The applicant also stated that this program manages loss of material, degradation of coatings, and corrosion of electrical connector contact surfaces exposed to air with borated water leakage. The applicant further stated that borated water leakage from components outside the scope of the program established in response to GL 88-05 may affect SSCs that are subject to an AMR; therefore, the scope of this program includes all components that contain borated water and are in proximity of SSCs subject to an AMR, including systems and structures inside the containment building, auxiliary building, spent fuel building, and inner penetration area.
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 AMP XI.M10. As discussed in the Audit Report, the staff confirmed that Aging Management Review Results 3-19 these elements are consistent with the corresponding elements of GALL 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 AMP XI.M10 and, therefore, acceptable.
Operating Experience. LRA Section B.2.1.4 summarizes operating experience related to the Boric Acid Corrosion Program. The applicant provided four examples of operating experience.
In one instance of operating experience, the applicant described the engineering analysis conducted in response to detected boric acid crystalline deposits. The applicant stated that the source of the deposits was traced to pinhole leaks at a location above the observed deposits. The applicant also described the resultant corrective action that included the replacement of analogous hardware that the applicant considered susceptible to similar degradation. In other operating experience provided in the LRA, the applicant presented instances of engineering evaluations that led to appropriate component replacements in response to leakage detected during the program's inspections.
The applicant's operating experience indicated its cognizance of GL 88-05, Bulletin 2002-01 , and Information Notice (IN) 2003-02, which reported issues in nuclear power plants associated with boric acid leakage and subsequent corrosion reactions and provided details on engineering analyses and corrective actions taken in response to detected leakage of boric acid. In one recorded instance, the applicant described its process in which direct measurements and engineering analyses were provided to establish a quantified assessment of corrosion effects on components contacted by boric acid due to leakage. In another recorded instance of operating experience, the applicant described an instance where a service water leak led to deterioration of a stainless steel tube which resulted in boric acid leakage. The applicant stated that the detection limits for chlorides were revised as part of an improvement in plant leak detection methods.
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. 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 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 and, 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 notes 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 also notes that the applicant committed (Commitment No. 4) to ongoing implementation of the existing Boric Acid Aging Management Review Results 3-20 Corrosion Program for managing aging of applicable components during the period of extended operation.
The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's Boric Acid Corrosion 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). 3.0.3.1.5  Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Summary of Technical Information in the Application. LRA Section B.2.1.5 describes the existing Nickel
-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program (hereafter,Nickel-Alloy Head Penetration Program) as consistent with GALL 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 cracking due to primary water stress
-corrosion cracking (PWSCC) in a reactor coolant environment and inspects for boric acid leakage residue on nickel
-alloy pressure vessel head penetration nozzles. The applicant also stated that the program includes the reactor vessel closure head, the upper vessel head penetration nozzles, and associated J groove welds. The applicant further stated that cracking was mitigated through control of water chemistry. The applicant also stated that the aging effects of cracking and loss of material were managed through a combination of surface and volumetric inspection techniques as described in ASME Code Case N
-729-1 as modified by 10 CFR 50.55a(g)(6)(ii)(D)(2) through (6).
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 AMP XI.M11A. The staff confirmed that these elements are consistent with the corresponding elements of GALL AMP XI.M11A. Based on its review, the staff finds that elements one through six of the applicant's Nickel
-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program are consistent with the corresponding program elements of GALL AMP XI.M11A and, therefore, acceptable. Operating Experience. LRA Section B.2.1.5 summarizes operating experience related to the Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program. In this section, the applicant stated that it has not detected PWSCC in any of the upper vessel head penetration nozzles. The applicant also stated that it preemptively replaced both the Unit 1 and Unit 2 heads in 2005 with heads constructed from PWSCC resistant material (Alloys 690 and 52). As evidence of the Aging Management Review Results 3-21 effectiveness of its AMP, the applicant provided three examples. Each of these examples addresses the attentiveness of the applicant, through the application of its AMP, to the potential for, and mitigation of, PWSCC. The applicant cited:  (1) its preemptive replacement of the heads for Units 1 and 2, (2) its work with the fabricator of the heads to identify and reduce indications observed in the new heads, and (3) its prompt incorporation in its AMP of changes to its ISI program for its upper head as directed by the revision to NRC Order EA 009 and ASME Code Case N
-729-1. The staff reviewed operating experience information which is contained in the application and in the GALL Report and which has occurred since the publication of the GALL Report, to determine whether 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 and, therefore, the staff finds it acceptable.
UFSAR Supplement. LRA Section A.2.1.5 provides the UFSAR supplement for the Nickel
-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program. The staff reviewed this UFSAR supplement description of the program and notes that it conforms to the recommended description for this type of program as described in SRP-LR Table 3.2-2. The staff also notes that the applicant committed (Commitment No. 5) to ongoing implementation of the existing Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program for managing aging of applicable components during the period of extended operation.
The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's Nickel
-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program, the staff finds that program elements 1
-6 and 10 are consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended 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  Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)
Summary of Technical Information in the Application.
LRA Section B.2.1.6 describes the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program as a new program that includes condition monitoring activities to provide assurance that RCS CASS Aging Management Review Results 3-22 components susceptible to thermal aging embrittlement meet the intended functions. The RCS CASS components are maintained by inspecting and evaluating the extent of thermal aging embrittlement in accordance with the requirements of ASME Code Section XI, 1998 Edition, through the 2000 Addenda. The applica nt stated that t he ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program at Salem Units 1 and 2 is augmented by the implementation of the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program, which monitors the aging effect of the loss of fracture toughness due to thermal aging embrittlement of CASS component
: s. The applicant stated that the program elements for this new AMP are consistent with the program element criteria recommended in GALL AMP Xl.M12, "Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)," without exception or enhancement.
Staff Evaluation. GALL AMP XI.M12 establishes the criteria for determining whether a supplemental flaw tolerance assessment or volumetric or enhanced VT
-1 inspection techniques should be credited to manage reduction of fracture toughness due to thermal aging embrittlement in RCS CASS piping, piping components, or piping elements.
The letter from Christopher I. Grimes of the NRC to Douglas J. Walters of the NEI, "Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Components," May 19, 2000, provid es additional criteria for determining whether a particular CASS material is susceptible to thermal aging embrittlement and describes aging management strategies for these materials. The guidance in GALL AMP XI.M12 references the additional guidelines provided in the May 19, 2000, letter. The staff reviewed the information in LRA Section B.2.1.6 and the applicant's response to the staff's RAI questions dated June 3, 2010. The staff noted that the program elements for the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program were consistent with the program element criteria recommended in GALL AMP XI.M12. However, the staff asked the applicant to clarify certain issues in the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program
, as follows.
By letter dated May 14, 2010, the staff' issued RAI B.2.1.6-1 requesting the applicant to identify the scope of the subject CASS AMP and to provide the schedule of its implementation. By letter dated June 3, 2010, the applicant responded that the scope of the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program (also referred to as the CASS AMP or CASS program) is limited to the Salem RCS piping.
Specifically, the only components that are potentially susceptible to thermal aging embrittlement within the scope of the new CASS program are the CASS elbows within the RCS primary loop piping (i.e., the hot legs, crossover legs, and cold legs). The applicant evaluated these CASS elbows for aging management as component type "Reactor Coolant Pressure Boundary Components" in LRA Table 3.1.2-1. The applicant stated that there are no CASS vessels, pumps, or valves covered under the CASS program. The applicant also stated that the Salem reactor vessel is constructed of low
-alloy steel with a stainless steel cladding. The applicant further stated that the aging effects associated with the CASS pressurized water reactor (PWR) vessel internals are managed by the PWR Vessel Internals Program as shown in LRA Appendix B, Section B.2.1.7. The applicant stated that the aging effects associated with the CASS reactor coolant pump (RCP) casings and CASS valves are managed by the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program as shown in LRA Appendix B, Section B.2.1.1; Water Chemistry Program as shown in LRA Appendix B, Section B.2.1.2; and time
-limited aging analysis (TLAA). The staff finds that the applicant has clearly defined the scope of the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program and its response is acceptable.
 
Aging Management Review Results 3-23 The applicant stated that the CASS program will be implemented for Salem Unit 1 before the end of its 24th refueling outage, tentatively scheduled for April 2016. For Salem Unit 2, the CASS program will be implemented before the end of its 24th refueling outage, tentatively scheduled for April 2020. The period of extended operation starts on August 13, 2016, and April 18, 2020, for Salem Units 1 and 2, respectively. The staff finds that the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program will be implemented before the commencement of the period of extended operation and, therefore, is acceptable.
The applicant stated that the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program at Salem is augmented by the implementation of the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program. The staff notes that the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program requires inspection of only a limited number of welds in a piping system once every 10 years. The staff stated that UT is not reliable and not yet qualified in detecting flaws in CASS components. The staff also stated that surface and visual examinations detect flaws only after degradation has occurred. It is not clear to the staff how the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program can detect thermal aging embrittlement in the CASS components in time to prevent component degradation. In RAI B.2.1.6-2, the staff requested that the applicant discuss exactly how the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program is augmented and enhanced as a result of implementing the CASS AMP. By letter dated June 3, 2010, the applicant responded that currently, the welds associated with the CASS elbows are already within the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program, specifically the RI
-ISI program covering all Class 1 and Class 2 welds. Although these welds are considered Risk Category 4 by the RI
-ISI program, they are not selected for examination due to the inability of existing volumetric examination techniques to examine the welds due to the CASS composition of the elbows. The new CASS program does not change the frequency of examination of these welds because they are still within the RI
-ISI program. The applicant stated that since a qualified volumetric examination technique does not currently exist for CASS materials, Salem performed a component
-specific flaw tolerance evaluation for the CASS elbows, where a portion of the CASS elbow comprises the weld area subject to examination. The flaw tolerance evaluation concluded that the CASS elbows within the Salem RCS primary loop are tolerant of large flaws through the period of extended operation.
The applicant stated that it will manage the aging of the CASS components using the flaw tolerance evaluation. The applicant further stated that if a volumetric examination technique is qualified in the future, the RI
-ISI program at that time will determine whether: (1) the CASS elbow welds will be examined by the qualified volumetric technique in accordance with 10 CFR 50.55a requirements or (2) if the flaw tolerance evaluation will continue to be used for aging management of the CASS components. There are no new license renewal enhancements to the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program as a result of implementation of the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program.
The staff finds that the use of the flaw tolerance evaluation to monitor the structural integrity of the CASS components is consistent with the guidance in GALL AMP XI.M12 and, therefore, its use is acceptable. The staff notes that it has sponsored a research and development program at the Pacific Northwest National Laboratory on the qualification of UT of CASS material as Aging Management Review Results 3-24 shown in NUREG/CR
-6933, "Assessment of Crack Detection in Heavy
-Walled Cast Stainless Steel Piping Welds Using Advanced Low
-Frequency Ultrasonic Methods."  In addition, the staff is working with the ASME and nuclear industry to develop an ASME Code case for the UT of CASS material. In the near future, licensees should be able to perform ultrasonic examination of CASS material using the ASME Code case.
In RAI B.2.1.6-3, the staff asked the applicant to describe the flaw tolerance evaluation and discuss how the flaw tolerance evaluation will be implemented during the period of extended operation to ensure the structural integrity of the CASS components. The staff also asked the applicant to discuss how the CASS components will be inspected under the RI
-ISI program at Salem considering the requirements of the CASS AMP (e.g., whether the CASS AMP will increase the inspection frequency of the CASS components in the RI
-ISI program and whether thermal aging embrittlement will be a degradation mechanism considered in the RI
-ISI program). In its June 3, 2010 letter, the applicant responded that thermal aging embrittlement of the C ASS components will be managed by the Salem component
-specific flaw tolerance evaluation, since a qualified volumetric examination technique does not currently exist for CASS materials. The flaw tolerance evaluation has been incorporated into the Salem design basis.
As a result of implementation of the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program, the RI
-ISI program will be revised to use the flaw tolerance evaluation if any of the CASS elbow welds are selected for examination. The flaw tolerance evaluation concludes that the CASS elbows are tolerant of large flaws, where a very large flaw (e.g., 31 percent through
-wall with an aspect ratio of 6) would remain within the ASME Code Section XI acceptance criteria throughout the period of extended operation, thereby ensuring the structural integrity of the CASS components.
The applicant noted that performance of a flaw tolerance evaluation is identified as one acceptable approach for managing the aging effect of thermal aging embrittlement of CASS components as suggested in GALL AMP XI.M12. The objective of the flaw tolerance evaluation was to determine whether the CASS components are tolerant of large flaws (i.e., an initial flaw of a large size can remain within the ASME Code Section XI acceptance criteria for a plant operation life of 60 years). To determine whether the CASS elbows are tolerant of large flaws, the applicant calculated acceptable maximum initial flaw sizes for limiting cases by determining the maximum allowable final flaw based on ASME Code Section XI acceptance criteria and subtracting the fatigue crack growth over incremental plant operation durations. The results of the flaw tolerance evaluation are presented in curves of maximum allowable initial flaw sizes as a function of aspect ratios. The Salem component
-specific flaw tolerance evaluation demonstrated that the susceptible CASS components are tolerant of large flaws. The following provides a detailed description of the Salem component
-specific flaw tolerance evaluation.
The NRC Grimes letter dated May 19, 2000, provides the screening criteria for determining the CASS components susceptible to thermal aging embrittlement. The CASS components that were considered susceptible to thermal aging embrittlement were the CASS elbows installed in the Salem Units 1 and 2 RCS primary loop. All of the CASS elbows within the primary loop:  (1) were fabricated of SA351 CF8M, (2) were static
-cast, (3) had a molybdenum content exceeding 2 percent, and (4) had varying ferrite levels from 8.81 percent up to 22.17 percent. The component
-specific flaw tolerance evaluation, Westinghouse Proprietary Document: LTR-PAFM-09-60, Revision 0, "Flaw Tolerance Evaluation for Susceptible CASS Reactor Aging Management Review Results 3-25 Coolant Piping Components in Salem Units 1 and 2," used the flaw evaluation guidelines provided in the Grimes letter. Since none of the CASS elbows had ferrite greater than 25 percent, ASME Code Section XI, paragraph IWB
-3640 flaw evaluation procedures were used in the flaw tolerance evaluation preparation. For the purposes of the Salem component
-specific flaw tolerance evaluation, the code of record for Salem, ASME Code Section XI, 1998 Edition, including the 2000 Addenda, was used.
The applicant determined the allowable flaw size at the end of the inspection/evaluation periods representing 10, 20, 30, and 40 years of service. These years of service are based on the 40-year transient design cycles. The applicant reviewed LRA Table 4.3.1-3, "Design Transients and 60-Year Projections for NSSS Class A and Class 1 Components at Salem Unit 1," and LRA Table 4.3.1-4, "Design Transients and 60
-Year Projections for NSSS Class A and Class 1 Components at Salem Unit 2," and concluded that the transient cycles projected for 60 years of operation were bounded by the corresponding 40
-year transient design cycles. Therefore, the inspection/evaluation periods are valid through the period of extended operation. The applicant stated that the flaw tolerance evaluation results correspond to 15, 30, 45, and 60 years of plant operation.
In applying the ASME Code Section XI acceptance criteria, the end
-of-evaluation allowable flaw size is defined as the flaw size to which the detected or postulated flaw is allowed to grow until the next inspection period. The end
-of-evaluation period flaw size is a function of stresses, crack geometry, and material properties. The end
-of-evaluation period is defined as the service life from the time of flaw detection to the time of the next scheduled examination or planned repair, or at the end of life for the component. The flaw tolerance evaluation determined the allowable flaw sizes for the appropriate limiting load conditions. The first of these allowable flaw sizes was calculated using stresses from the governing normal, upset, and test conditions. The second of these allowable flaw sizes was calculated based on stresses for the governing emergency and faulted conditions. The most limiting allowable flaw size determined for the normal, upset, emergency, test, and faulted conditions was used as the maximum end-of-evaluation period flaw size.
The applicant stated that the end
-of-evaluation period flaw sizes of IWB
-3640 in ASME Code Section XI, for the high toughness base materials, were determined based on the assumption that plastic collapse would be achieved and would be the dominant mode of failure. The applicant stated that however, due to the reduced toughness of the susceptible CASS material resulting from thermal aging embrittlement, it is possible that crack extension and unstable ductile tearing could occur and be the dominant mode of failure. The applicant also stated that to account for this effect, the Grimes letter requires that the "Z factors" for submerged arc welds given in ASME Code Section XI, Appendix C be used as a multiplier to increase the limiting loads used in determining the maximum end
-of-evaluation period allowable flaw size. The applicant further stated that this is supported by the results from the Argonne National Laboratory Research Program indicating that the lower
-bound fracture toughness of thermally-aged cast stainless steel is similar to that of submerged arc welds, as stated in the Grimes letter.
The applicant analyzed fatigue flaw (crack) growth considering thermal, deadweight, seismic, pressure, and thermal transient stresses and residual stresses. The 40
-year design transient cycles, which bound the corresponding 60
-year projected transient cycles, were considered in the fatigue crack growth analyses. The applicant used welding residual stress values from the technical article, "Evaluation of Flaws in Austenitic Steel Piping
-Section XI Task Group for Piping Flaw Evaluation," Transactions of ASME, Journal of Pressure Vessel Technology, Aging Management Review Results 3-26 Volume 108, August 1986, pp. 352-366, in the fatigue crack growth analysis. In addition, the applicant considered residual stresses resulting from mechanical stress improvement procedures (MSIP) applied at the reactor vessel nozzle
-to-safe end dissimilar metal weld regions for Salem Units 1 and 2 reactor vessel inlet (cold leg) nozzle elbows to obtain the most limiting fatigue crack growth results. The residual stresses by MSIP are added algebraically (algebraic sum method) to the thermal, deadweight, seismic, pressure, and thermal transient stresses in the fatigue crack growth analysis. Although Salem Unit 2 has not completed MSIP on its cold leg (inlet) reactor vessel nozzle
-to-safe end welds, the applicant nevertheless accounted for residual stresses, thereby adding conservatism to the flaw tolerance evaluation.
The staff notes that the purpose of the MSIP is to alter the residual stress pattern in the dissimilar metal weld, placing the inner part of the weld in compression, thus inhibiting crack initiation. If cracks are present in the weld, the residual stress pattern is more complex. If cracks are shallow, the MSIP will probably prevent further crack growth, as long as the residual stress remains favorable (i.e., compressive). For deeper cracks, particularly those penetrating deeper than halfway through the weld wall, the crack tip is likely to experience a general tensile stress field after MSIP, which may cause the crack to propagate in the weld. NUREG
-0313, Revision 2, "Technical Report on Material Selection and Processing Guidelines for BWR Coolant Pressure Boundary Piping," provides limitations on the MSIP application based on the crack size. The CASS elbow located next to the dissimilar metal weld may experience residual (tensile) stresses as a result of the MSIP of the dissimilar metal weld. The staff finds acceptable that the applicant considered the impact (residual tensile stresses) of the MSIP in the flaw tolerance evaluation for the CASS elbow.
The fatigue crack growth analysis procedure involves postulating an initial flaw (crack) at the susceptible component and predicting the flaw growth due to an imposed series of loading transients. The input required for a fatigue crack growth analysis is information necessary to I (range of crack tip stress intensity factor), which depends on the geometry of the crack, its surrounding structure, and the range of applied stresses in the crack area. The applicant derived the stress intensity factors for semi
-elliptical inside surface axial flaws using expressions found in the following technical literatures:  (1) Raju, I.S. and Newman, J.C., "Stress Intensity Factor Influence Coefficients for Internal and External Surface Cracks in Cylindrical Vessels," ASME Publication Pressure Vessel and Piping, Volume 58, 1982, pp. 37-48 and (2) Mettu, S.R. et al, NASA Lyndon B. Johnson Space Center Report No. NASA-TM-111707, "Stress Intensity Factors for Part
-through Surface Cracks in Hollow Cylinders," in Structures and Mechanics Division, July 1992. Similar calculations were performed for inside surface circumferential flaws based on the technical resource S. Chapuliot et al, "Stress Intensity Factors for Internal Circumferential Cracks in Tubes over a Wide Range of Radius over Thickness Ratios," ASME Pressure Vessel and Piping Volume 365, 1998.
I was calculated, the applicant calculated crack growth due to a particular stress cycle using the applicable crack growth reference curves for stainless steel in an air environment from ASME Code Section XI, Appendix C with an environmental factor of 2.0 to account for the PWR water environment. The factor of 2.0 is based on the following technical article:  "Evaluation of Flaws in Austenitic Steel Piping
-Section XI Task Group for Piping Flaw Evaluation," Transactions of ASME, Journal of Pressure Vessel Technology, Volume 108, August 1986, pp. 352-366. The incremental fatigue crack growth was added to the postulated initial crack size, and the analysis proceeded to the next cycle or transient.
The fatigue crack growth Aging Management Review Results 3-27 calculation was continued in this manner until all the 40
-year design transients for the design plant life were analyzed.
The applicant used bounding material properties, geometry, and stresses in each leg (hot, cold, and crossover) of the Salem Units 1 and 2 RCS primary loops. For a particular flaw shape and configuration, the maximum acceptable initial flaw size for a given service life (i.e., 10, 20, 30, 40 years), based on the original 40
-year transient design cycles which bound the 60 years of plant operation, was determined by subtracting the corresponding fatigue crack growth from the end-of-evaluation period allowable flaw size. The maximum acceptable initial flaw sizes for various flaw configurations and aspect ratios are provided in the flaw tolerance evaluation.
The applicant stated that for example, the results of the flaw tolerance evaluation for a flaw aspect ratio of 6 and plant operation duration of 60 years are shown in Table 1 below. As shown in Table 1 below, the maximum acceptable initial circumferential flaw depth is 31 percent through-wall for the susceptible hot leg elbows, which is the most limiting case.
Considering the wall thickness near the hot leg elbow weld of 2.50 inches, a circumferential flaw initiated at original plant startup, with a depth of up to 31 percent of the wall thickness, equating to 0.78 inches (0.31 x 2.50 inches) in depth, and having a length up to 4.68 inches, based on the aspect ratio of 6 (0.78 inches x 6 = 4.68 inches) would remain within the acceptance criteria of IWB-3640 for 60 years of plant service life. For all other flaw configurations and susceptible elbow locations tabulated in Table 1, the maximum acceptable initial flaw depths are larger than this most-limiting case. Therefore, even with thermal aging embrittlement, the Salem component-specific flaw tolerance evaluation concludes that the susceptible CASS elbows are tolerant of large flaws.
Table 1 Acceptable Initial Flaw Sizes (% Through
-wall Thickness) for Salem Susceptible CASS Elbow Locations (Aspect Ratio = 6, for a Plant Operation Duration of 60 years)
Susceptible CASS Limited Elbow Locations Axial Flaw Circumferential Flaw Acceptable Initial Flaw Size Allowable Final Flaw Size Acceptable Initial Flaw Size Allowable Final Flaw Size Hot Leg (Outlet)  43.4% 49% 31% 50% Crossover Leg 50.0% 59% 38.2% 62% Cold Leg (Inlet) 45.2% 52% 42.8% 75%  The staff finds that the applicant's flaw tolerance evaluation methodology is consistent with ASME Code Section XI, Appendix C and with the program elements in GALL AMP XI.M12 which references the guidance in the NRC (Grimes) letter dated May 19, 2000. Therefore, the flaw tolerance evaluation is acceptable.
On April 15, 2010, the staff audited the Westinghouse report, "Flaw Tolerance Evaluation for susceptible CASS Reactor Coolant Piping Components in Salem Units 1 and 2," LTR-PAFM-09-60, in the Westinghouse Satellite Office in Rockville, Maryland. This audit is part of the staff's review of the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program to verify the acceptability of the flaw tolerance evaluation. As part of the audit, Aging Management Review Results 3-28 the applicant provided response s to the staff's RAI regarding the subject flaw tolerance evaluation.
The Salem plant
-specific flaw tolerance evaluation showed residual stresses at the reactor vessel inlet nozzle safe end
-to-cold leg elbow weld regions as a result of the MSIP. In RAI B.2.1.6-7, the staff requested that the applicant discuss how the residual stresses are factored in the allowable flaw size calculation for the cold leg elbow and to identify the CASS elbows in the piping systems covered under the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program in eac h Unit that are affected by the MSIP. In its June 3, 2010 letter, the applicant responded that MSIP was implemented for the Salem Unit 1 reactor vessel inlet nozzle safe end
-to-cold leg elbow weld regions. MSIP has not been implemented for the Salem Unit 2 reactor vessel inlet nozzle safe end
-to-cold leg elbow weld regions.
To obtain the limiting fatigue crack growth results, the applicant considered the effects of residual stresses due to MSIP for all eight cold leg elbows in Salem Units 1 and 2, as well as those from the technical article "Evaluation of Flaws in Austenitic Steel Piping
-Section XI Task Group for Piping Flaw Evaluation," Transactions of ASME, Journal of Pressure Vessel Technology, Volume 108, August 1986, pp. 352-366. Although Salem Unit 2 has not completed MSIP on its cold leg (inlet) reactor vessel nozzle
-to-safe end dissimilar metal welds, the effects of MSIP residual stresses were conservatively accounted for in the flaw tolerance evaluation. The residual stresses due to MSIP were added algebraically (algebraic sum method) to the pressure, deadweight, seismic, and thermal transient stresses in the fatigue crack growth analysis as discussed above.
The resulting fatigue crack growth was then used to determine the maximum allowable initial flaw size for a given plant operation. The maximum allowable initial flaw size is determined by the duration of plant operations from the maximum allowable end
-of-evaluation period flaw size which was determined in accordance with the flaw evaluation and acceptance criteria in the ASME Code Section XI. The Salem Unit 1 cold leg elbows are not susceptible to thermal aging embrittlement since their ferrite content is less than 14 percent. One of the cold leg elbows on Salem Unit 2 has ferrite content less than 14 percent with the remaining three legs between 14 percent and 17 percent. Although Salem Unit 2 has not yet implemented MSIP on the reactor vessel inlet nozzle
-to-safe end dissimilar metal welds, the projected residual stresses associated with MSIP were conservatively addressed in the flaw tolerance evaluation for Salem Unit 2. The applicant stated that the four CASS elbows welded to the Salem Unit 2 reactor vessel inlet nozzle safe ends (cold legs) are also affected by MSIP.
The staff finds that the residual stresses due to MSIP were added algebraically to the other stresses in the flaw tolerance evaluation and that the applicant has identified the CASS components that may be susceptible to thermal aging embrittlement based on their ferrite content. Therefore, the staff finds that the applicant has satisfactorily addressed the issue.
Figures 6-1 to 6-6 in the Salem flaw tolerance evaluation show flaw tolerance curves are applicable to 40 years, but not 60 years. In RAI B.2.1.6-8, the staff requested that the applicant explain why the flaw tolerance curves for 60 years were not generated. By letter dated June 3, 2010, the applicant responded that the flaw tolerance curves presented in Figures 6-1 to 6-6 of the Salem component
-specific flaw tolerance evaluation were generated based on Salem's 40
-year thermal transient design cycles, which are listed in LRA Table 4.3.1-2, "Design Transient Cycles for NSSS Class A and Class 1 Components at Salem Units 1 and 2."  As part Aging Management Review Results 3-29 of the LRA, the number of thermal transient cycles were projected for 60 years of operation and are shown in LRA Tables 4.3.1-3, "Design Transients and 60-Year Projections for NSSS Class A and Class 1 Components at Salem Unit 1," and 4.3.1
-4, "Design Transients and 60-Year Projections for NSSS Class A and Class 1 Components at Salem Unit 2," for Salem Units 1 and 2, respectively.
LRA Section 4.3.1 states that the thermal transient cycles projected for 60 years are bounded by the original 40
-year thermal transient design cycles. Therefore, the flaw tolerance curves presented in Figures 6
-1 to 6-6 of the flaw tolerance evaluation, which are based on the original 40-year thermal transient design cycles, are valid for up to 60 years of plant operation.
The staff finds that the Salem flaw tolerance evaluation used the 40
-year transient cycles; however, the 40
-year transient cycles bound the 60
-year project cycles. Therefore, the staff finds this acceptable.
In RAI B.2.1.6-9, the staff requested that the applicant discuss how an actual flaw would be dispositioned if detected in a CASS elbow exceeding the acceptable initial flaw size. By letter dated June 3, 2010, the applicant responded that if Salem uses a qualified volumetric technique for examining the CASS elbows, and if a flaw is detected that exceeds the acceptable initial flaw size, this finding will be documented in the corrective action program and the flaw would be dispositioned by performing an additional flaw evaluation based on the as
-found flaw configuration in accordance with the evaluation procedure and acceptance criteria in ASME Code Section XI, paragraph IWB
-3640. The additional flaw evaluation results will be used to determine an appropriate inspection frequency. If required by the flaw evaluation, additional corrective actions, including such options as repair or replacement, would be specified in accordance with the corrective action program.
The staff finds that the applicant will disposition detected flaws in the CASS components in accordance with ASME Code Section XI, paragraph IWB
-3640, therefore, it is acceptable.
In RAI B.2.1.6-10, the staff requested that the applicant describe in detail how the allowable flaw sizes were calculated. By letter dated June 3, 2010, the applicant responded that Table 6-1 of the Salem component
-specific flaw tolerance evaluation provides both the maximum allowable (acceptable) initial and final flaw sizes for susceptible CASS elbows in the hot leg, crossover leg, and cold leg locations. These flaw sizes are listed as percent through
-wall thickness, based on an aspect ratio (ratio of flaw length to flaw depth for surface flaw) of 6, which is consistent with the assumed aspect ratio in the 1998 Edition of ASME Code Section XI, Article L
-3000, and a service life of 40 years. The staff has not yet approved the ASME Code Section XI, Appendix L where Article L
-3000 is referenced. However, the applicant's use of aspect ratio 6 in this particular case is not objectioinable.
The maximum end
-of-evaluation period (final) flaw size was first determined in accordance with the flaw evaluation and acceptance criteria given in ASME Code Section XI, paragraph IWB-3640, which is consistent with the flaw evaluation methodology presented in the NRC Grimes letter. ASME Code Section XI, Appendix C provides the limit load equations and Z factors for the IWB
-3640 flaw evaluation. A fatigue crack growth evaluation was performed to determine fatigue crack growth for various plant operation durations (i.e., 10, 20, 30, and 40 years) based on the Salem
-specific 40
-year design thermal transients cycles.
 
Aging Management Review Results 3-30 The maximum allowable initial flaw size for a given plant operation duration (i.e., 10, 20, 30, or 40 years) was then calculated by subtracting the fatigue crack growth determined for that plant operation duration from the maximum allowable end-of-evaluation period (final) flaw size.
The staff finds that the applicant used appropriate methodology in the ASME Code Section XI and in the NRC Grimes letter to obtain the allowable crack size. Therefore, the staff finds that the applicant has satisfactorily addressed the issue.
In RAI B.2.1.6-11, the staff requested that the applicant: (1) confirm that for the fatigue crack growth calculation, the flaw growth rate for the PWR water environment was used; and (2) to discuss whether the flaw growth rate used in the calculation is consistent with the flaw growth rate in the ASME Code Section XI, Appendix C. In its June 3, 2010 letter, the applicant responded that the fatigue crack growth rate for the PWR water environment was used in the fatigue crack growth calculation. The fatigue crack growth rate curves used in the flaw tolerance evaluation were consistent with the curves in the ASME Code Section XI, Appendix C; however, the crack growth rate curves were modified to account for the PWR water environment. The fatigue crack growth rate curves contained in the ASME Code Section XI, Appendix C are for austenitic stainless steel in an air environment. The Salem flaw tolerance evaluation accounted for the PWR water environment by applying an environmental factor of 2 to the air environment curve in ASME Code Section XI, Appendix C. The environmental factor of 2 is based on the technical article "Evaluation of Flaws in Austenitic Steel Piping
-Section XI Task Group for Piping Flaw Evaluation," Transactions of ASME, Journal of Pressure Vessel Technology, Volume 108, August 1986, pp. 352
-366. The staff finds that the applicant has used an appropriate fatigue crack growth rate curve with an environmental factor of 2. This multiplier is consistent with the staff position and is acceptable.
The Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program references the requirements of ASME Code Case N
-481, "Alternate Examination Requirements for Cast Austenitic Pump Casings," for the inspection of pump casings and valve bodies as suggested in GALL AMP XI.M12. The NRC approved ASME Code Case N
-481 in RG 1.147, Revision 14. However, the ASME annulled Code Case N
-481 on March 28, 2004, after the requirements of Code Case N
-481 were incorporated into the ASME Code Section XI. Subsequently, the NRC also annulled the code case as indicated in RG 1.147, Revision 15. In RAI B.2.1.6-4, the staff requested that the applicant justify the use of Code Case N
-481 or propose alternative examinations for pump casings and valve bodies as part of the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program.
By letter dated June 3, 2010, the applicant responded that the "Program Description" of the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program incorrectly referenced the alternative inspection requirements of ASME Code Case N
-481 as being adequate for all pump casings and valve bodies. The Class 1 pump casings and valve bodies are within scope for aging management under the ASME Section XI, Subsections IWB, IWC, and IWD Program as shown in LRA Appendix B, Section B.2.1.1; the Water Chemistry Program as shown in LRA Appendix B, Section B.2.1.2; and the TLAA. The correct reference for inspection requirements of pump casings and valve bodies is found in the ASME Code Section XI, Table IWB
-2500-1, Categories B-L-2 and B-M-2 for pump casing and valve body inspections, respectively. Therefore, no alternative examinations are required for the CASS Aging Management Review Results 3-31 pump casings and valve bodies under the CASS program, and the ASME Code Case N-481 will not be used for these components.
As a result of the incorrect reference to ASME Code Case N-481, the applicant revised LRA Appendix A, Section A.2.1.6, page A
-10, second paragraph. The staff finds that the applicant has deleted the reference to Code Case N
-481 in the revised paragraph in LRA Section A.2.1.6. Therefore, the staff finds that the applicant has satisfactorily addressed the issue.
The Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program states that, "-Flaw tolerance evaluation for components with ferrite content up to 25 percent is performed according to IWB-3640 for submerged arc welds (SAW)-"  In RAI B.2.1.6-5, the staff requested that the applicant clarify the intent of the above statement and discuss whether the Salem units have CASS components with ferrite content greater than 25 percent.
By letter dated June 3, 2010, the applicant responded that the intent of the statement, "-Flaw tolerance evaluation for components with ferrite content up to 25 percent is performed according to IWB-3640 for submerged arc welds (SAW)-," is to reiterate the acceptance criteria discussed in GALL AMP XI.M12. If the ferrite content does not exceed 25 percent, the flaw tolerance evaluation would be performed in accordance with the principles associated with the ASME Code Section XI, paragraph IWB
-3640 procedures for SAW, disregarding the ASME Code ferrite restriction of 20 percent in IWB
-3641(b)(1), in accordance with the NRC Grimes letter. If the ferrite content for the CASS material was greater than 25 percent, then the flaw tolerance evaluation would have been performed on a case-by-case basis using fracture toughness data. Since the material of the Salem CASS components susceptible to thermal aging embrittlement contains less than 25 percent ferrite, the flaw tolerance evaluation was performed in accordance with IWB-3640 procedures for SAW, disregarding the ferrite ASME Code restriction of 20 percent in IWB
-3641(b)(1), in accordance with the NRC Grimes letter.
The applicant clarified further that the CASS components covered under the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program do not have ferrite content values greater than 25 percent. The applicant also stated that the flaw tolerance evaluation, Westinghouse letter, LTR
-PAFM-09-60, "Flaw Tolerance Evaluation for Susceptible CASS Reactor Coolant Piping Components in Salem Units 1 and 2," dated July 2009 was prepared for, and is only applicable to, the susceptible CASS components (i.e., elbows) in the CASS program. The staff finds that the applicant clarified the issue on the ferrite content that the RCS primary loop piping does not have CASS components with ferrite content values greater than 25 percent. The Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program cites an operating experience of cracking in impeller vanes of RCPs attributed to thermal aging embrittlement. In RAI B.2.1.6-6, the staff requested that the applicant discuss whether the impeller vane degradation is applicable to the Salem units and whether the impeller vanes at Salem have been inspected. By letter dated June 3, 2010, the applicant responded that the operating experience citing impeller vane degradation was initially thought to potentially be due to thermal aging embrittlement. Upon further review, the applicant has determined that the operating experience of the impeller vane degradation is not applicable to the Salem units. The Aging Management Review Results 3-32 cause of failure associated with the impeller vane operating experience was due to internal shrinkage during the casting process and is not caused by thermal aging embrittlement.
The applicant deleted the reference to the impeller vane in the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program. The staff finds it acceptable that the reference to impeller vane cracking is deleted from the CASS program because the cracking of the impeller vanes of RCPs is not related to the thermal aging embrittlement degradation mechanism and is not applicable to the Salem units.
Based on its review, the staff finds that the applicant's aging management basis and program elements in the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program are acceptable because they are consistent with the staff's recommended aging management basis and program elements that are defined in GALL AMP XI.M12.
UFSAR Supplement. LRA Section A.2.1.6 provides the UFSAR supplement for the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program. The staff reviewed this UFSAR supplement description of the program and notes that it conforms to the recommended description for this type of program as described in SRP
-LR Table 3.1-2. The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusio n. On the basis of its review of the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) 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 of RCS CASS components 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 a nd concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.1.7  PWR Vessel Internals Summary of Technical Information in the Application. In LRA Section B.2.1.7, the applicant described its PWR Vessel Internals Program, stating that this new program commits to the following:
  (1) participate in the industry programs for investigating and managing aging effects on reactor internals (2) evaluate and implement the results of the industry programs as applicable to the reactor internals  (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval The applicant then concludes the following:
The new PWR Vessel Internals aging management program will provide reasonable assurance that the changes in dimensions, cracking, loss of fracture Aging Management Review Results 3-33 toughness, and loss of preload aging effects will be adequately managed so that the intended functions of components within the scope of license renewal will be maintained consistent with the current licensing basis during the period of extended operation.
Staff Evaluation. For RPV internals, the management of postulated aging effects that may occur for PWRs is covered in the following LRA sections:
Section 3.1.2.2.6, "Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement and Void Swelling" Section 3.1.2.2.9, "Loss of Preload Due to Stress Relaxation" Section 3.1.2.2.12, "Cracking Due to Stress Corrosion Cracking and Irradiation
-Assisted Stress Corrosion Cracking (IASCC)"
Section 3.1.2.2.15, "Changes in Dimensions Due to Void Swelling" Section 3.1.2.2.17, "Cracking Due to Stress Corrosion Cracking, Primary Water Stress Corrosion Cracking, and Irradiation
-Assisted Stress Corrosion Cracking" No further evaluation is recommended by the GALL Report if the applicant commitment specified under the Table IV.B3 column heading "Aging Management Program (AMP)" for these RPV internals (or line items) is confirmed as specified below:
No further aging management review is necessary if the applicant provides a commitment in the FSAR supplement to (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval.
The above commitment is also stated as a requirement in SRP
-LR Sections 3.1.2.2.6, 3.1.2.2.9, 3.1.2.2.12, 3.1.2.2.15, and 3.1.2.2.17. By comparing the contents of the PWR Vessel Internals Program with Commitment No. 7 (LRA Table A.5) and with the commitments specified in the SRP-LR and GALL Report Table IV.B2, the staff concludes that the PWR Vessel Internals Program is equivalent the SRP-LR required commitment for specific PWR RPV internals. Hence, the staff considers the applicant's PWR Vessel Internals Program, at the present form, as a means for fulfilling Commitment No. 7, designed solely to meet a key aging management guideline provided in SRP
-LR Sections 3.1.2.2.6, 3.1.2.2.9, 3.1.2.2.12, 3.1.2.2.15, and 3.1.2.2.17 for specific PWR RPV internals. Due to this unique feature, the staff determined that the 10 evaluation elements for a typical GALL Report AMP do not apply to the applicant's PWR Vessel Internals Program.
In addition to the PWR Vessel Internals Program, the staff verified that LRA Sections 3.1.2.2.12 and 3.1.2.2.17 also require control of water chemistry to mitigate the specific aging mechanism(s) for RPV internals
. The staff's evaluation of water chemistry can be found in SER Section 3.0.3.1.2.
 
Aging Management Review Results 3-34 The staff noted that the lists of components in LRA Table 3.1.2-3 under the aging effects of LRA Sections 3.1.2.2.6, 3.1.2.2.9, 3.1.2.2.12, 3.1.2.2.15, and 3.1.2.2.17 for the RPV internals do not seem to be consistent with the lists of components in GALL Report Table IV.B3, for which the PWR Vessel Internals Program is credited for part or all of the aging management. These seeming inconsistencies are largely due to:  (1) the plant
-specific features of the RPV internals which contain more components than those listed in GALL Report Table IV.B2 and (2) the applicant's use of several subcomponents to represent a typical component in GALL Report Table IV.B2. SER Sections 3.1.2.2.6, 3.1.2.2.9, 3.1.2.2.12, 3.1.2.2.15, and 3.1.2.2.17 contain the staff's resolution of the RAIs related to these inconsistencies.
Based on the staff's review above and the staff's resolution of RAIs related to inconsistencies of component listings between the LRA and the GALL Report, the staff concludes that the PWR Vessel Internals Program, in its present form, is equivalent to Commitment No. 7, which is designed to meet the SRP
-LR and GALL Report Table IV.B2 requirements for the RPV internals under the aging mechanisms identified earlier. Hence, working with appropriate AMP(s), as specified in GALL Report Table IV.B3, the PWR Vessel Internals Program is acceptable for management of aging effects listed above for the RPV internals. In the future, the program contents will be replaced by the plant
-specific version of the industry program documented in Modification/Rework Package (MRP)
-227, "Materials Reliability Program:  Pressurized Water Reactor Internals Inspection and Evaluation Guidelines," with the NRC
-specified conditions. The revised PWR Vessel Internals Program will be submitted to the staff for review and approval in accordance with Commitment No. 7.
UFSAR Supplement. LRA Section A.2.1.7 provides the UFSAR supplement for the PWR Vessel Internals Program. The staff reviewed this UFSAR supplement description of the program and determines that the information in the supplement provides an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's PWR Vessel Internals Program, the staff determines that this AMP is a unique plant
-specific program designed as a means for fulfilling Commitment No. 7. The staff concludes that, combined with other specific Salem AMPs, the applicant has demonstrated that the effects of aging for the RPV internals will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.1.8  Steam Generator Tube Integrity Summary of Technical Information in the Application. LRA Section B.2.1.10 describes the existing Steam Generator Tube Integrity Program as consistent with GALL AMP XI.M19, "Steam Generator Tube Integrity."  The applicant stated that the Steam Generator Tube Integrity Program manages the aging effects of the steam generators, including the tubes, plugs, and tube support plates in reactor coolant or treated water environments.
The applicant stated that the program provides for the operation, maintenance, testing, inspection, and repair of the steam generators to ensure that technical specification (TS)
, surveillance requirements, ASME Code requirements, and Maintenance Rule performance criteria are met. The applicant further stated that the aging effects include cracking, loss of material, reduction of heat transfer, and wall thinning. The tubing material in the steam Aging Management Review Results 3-35 generators in Salem Units 1 and 2 is thermally
-treated Alloy 600 and thermally
-treated Alloy 690, respectively. The applicant stated that the dominant degradation mode for the steam generator tubes at Salem is wear. The program implements NEI 97-06, "Steam Generator Program Guidelines," which establishes a framework for prevention, inspection, evaluation, repair, and leakage monitoring measures. The applicant stated the following:
The program includes preventative measures to mitigate degradation related to corrosion phenomena, assessment of degradation mechanisms, inservice inspection (ISI) of steam generator tubes, plugs, and tube supports to detect degradation, evaluation, and plugging or repair, as needed, and leakage monitoring to maintain the structural and leakage integrity of the pressure boundary. 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 AMP XI.M19. As discussed in the Audit Report, the staff confirmed that these elements are consistent with the corresponding elements of GALL AMP XI.M19.
However, the staff noted one discrepancy in the LRA AMP relative to the GALL Report AMP which the applicant will fix under its corrective action program.
The applicant's procedure CY
-AP-120-340, "Primary to Secondary Leakage Monitoring Procedures," requires entry into Action Level 3, Condition 1
, when primary to secondary leakage equals or exceeds 140 gallons per day (gpd) in any steam generator. The GALL Report references NEI 97-06, which in turn references EPRI Report 10088219, "PWR Primary to Secondary Leakage Guidelines," Revision 3. Revision 3 of these guidelines requires entry into Action Level 3, Condition 1 when primary to secondary leakage is increasing by greater than or equal to 30 gpd/hour and is equal to or exceeding 75 gpd. During the audit, the applicant stated that the plant procedure was incorrect. The applicant has entered this into its corrective action program as Notification 20451464. The staff finds this acceptable; therefore, this issue is resolved and requires no further action.
In comparing program elements one through six of the applicant's program to the corresponding elements of GALL AMP XI.M19, the staff noted that each element of the applicant's program is consistent with the corresponding element of GALL AMP XI.M19.
Operating Experience. LRA Section B.2.1.10 summarizes operating experience related to the Steam Generator Tube Integrity Program. The applicant replaced the original steam generators in Units 1 and 2 in 1996 and 2008, respectively. The original steam generators in Unit 1 were replaced with Westinghouse Model F steam generators with thermally
-treated Alloy 600 tubes. The original steam generators in Unit 2 were replaced with AREVA 61/19T steam generators with thermally
-treated Alloy 690 tubes. The applicant included the following as part of the operating experience:
A separate report following the 2004 [Unit 1] outage indicated that the estimated steam generator deposit ingress (sludge) has been decreasing per cycle since the replacement of the steam generators in 1996. For example, the estimated Aging Management Review Results 3-36 sludge accumulation for all four steam generators in the fourth cycle following replacement was 1086 lbs as compared to 2677 lbs estimated in the first cycle following replacement.
The materials of construction for the [Unit 2] replacement steam generators have better resistance to aging effects than those in the original steam generators.
Examples include the use of Inconel 690 thermally
-treated tubes in the replacement steam generators as compared to the Inconel 600 mill
-annealed tubes of the original steam generators. Also, the tube support plates and anti-vibration bars in the replacement steam generators are made of stainless steel as compared to the carbon steel components in the original steam generators
. 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. 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.
The staff confirmed that the applicant addressed operating experience identified after issuance of the GALL Report. Based on its review, the staff finds that:  (1) 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 (2) implementation of this program has resulted in the applicant taking appropriate corrective actions. Therefore, the operating experience program element satisfies the criterion in SRP
-LR Section A.1.2.3.10 and 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 notes that it conforms to the recommended description for this type of program as described in SRP
-LR Table 3.1
-2. The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Steam Generator Tube 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).
Aging Management Review Results 3-37 3.0.3.1.9  Open-Cycle Cooling Water System 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 GALL AMP XI.M20, "Open-Cycle Cooling Water System."  The applicant stated that its program includes surveillance and control techniques to manage aging effects caused by biofouling, corrosion, erosion, protective coating failures, and silting in the open
-cycle cooling water system. The applicant stated that the program provides assurance that aging effects from cracking, loss of material, increase in porosity and permeability, loss of strength, hardening, and reduction of heat transfer are maintained at acceptable levels. The applicant also stated that activities and guidelines from GL 89
-13 provide for management of aging effects in raw water cooling systems. The applicant further stated that sodium hypochlorite injection, system and component testing, visual inspections, and other nondestructive examinations (NDEs) are performed to ensure that aging effects are managed. The applicant also listed major components for these systems as pumps, piping, piping elements, piping components, heat exchangers, and tanks.
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 AMP XI.M20. As discussed in the Audit Report, the staff confirmed that these elements are consistent with the corresponding elements of GALL AMP XI.M20. Based on its audit, the staff finds that elements one through six of the applicant's Open
-Cycle Cooling Water System Program are consistent with the corresponding program elements of GALL AMP XI.M20 and, therefore, acceptable.
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 recurrent problems in the early operation of the service water system. According to the applicant, this project began the replacement of most of the safety
-related carbon steel piping with 6 percent molybdenum stainless steel, and many of the safety
-related heat exchanger tube bundles were replaced with corrosion resistant titanium or 6 percent molybdenum stainless steel. The applicant stated that it upgraded material s for other component types including valves and orificies in the service water system. The applicant stated that these changes in component materials demonstrate that the Open
-Cycle Cooling Water System Program is effective in detecting and correcting issues to ensure the long
-term reliability of the system for the period of extended operation.
In addition, the applicant stated that Salem Unit operators discovered an underground service water leak. The applicant's investigation of the problem determined that a joint had started to leak due to a crack in the steel ring of the bell and spigot joint. The applicant determined that the cause of the joint failure was the loss of caulking, which had previously protected the carbon steel portions of the joint. As noted in the operating experience discussion of the LRA (Appendix B.2.22) for the Buried Piping Inspection Program for this issue, an extent of condition study identified internal corrosion on other bell and spigot joints, which prompted the installation of an internal elastomer seal on each joint of the nuclear service water inlet headers. The applicant stated that maintenance tasks were established to inspect the joints every other Aging Management Review Results 3-38 outage, in conjunction with the piping inspections. The applicant further stated that this operational experience provided evidence that the Open
-Cycle Cooling Water System Program identifies and corrects deficiencies in the open
-cycle cooling water system, ensuring the long-term reliability of the system for the period of extended operation.
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. 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 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 and, therefore, the staff finds it acceptable.
UFSAR Supplement. LRA Section A.2.1.11 provides the UFSAR supplement for the Open-Cycle Cooling Water System Program. The staff reviewed this UFSAR supplement description of the program and notes 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 notes that the applicant committed (Commitment No. 11) to ongoing implementation of the existing Open-Cycle Cooling Water System Program for managing aging of applicable components during the period of extended operation.
The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's Open
-Cycle Cooling Water System 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 Compressed Air Monitoring Summary of Technical Information in the Application. LRA Section B.2.1.14 describes the existing Compressed Air Monitoring Program as consistent with GALL AMP XI.M24, "Compressed Air Monitoring."  The applicant stated that the program consists of testing, monitoring, and inspection of the piping, piping components, piping elements, compressor housings, and tanks for loss of material due to general, pitting, and crevice corrosion in the compressed air systems. The applicant also stated this program includes frequent leak testing of valves, piping, and other system components, especially those constructed of carbon and Aging Management Review Results 3-39 stainless steel; and preventive monitoring that checks air quality at multiple locations in the system to ensure that oil, water, rust, dirt, and other contaminants are kept within accepted limits. The applicant further stated that the program provides for timely corrective actions to ensure that the system is operated within accepted limits.
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 AMP XI.M24. As discussed in the Audit Report, the staff confirmed that these elements are consistent with the corresponding elements of GALL AMP XI.M24. Based on its audit, the staff finds that elements one through six of the applicant's Compressed Air Monitoring Program are consistent with the corresponding program elements of GALL AMP XI.M24 and, therefore, acceptable.
Operating Experience. LRA Section B.2.1.14 summarizes operating experience related to the Compressed Air Monitoring Program. The applicant stated that the program is effective in assuring that intended functions will be maintained consistent with the CLB for the period of extended operation. The applicant also stated that on a system walkdown of the compressed air system, signs of surface rust were identified on control manifolds for Unit 1. The applicant further stated that it determined that the condition was not a threat to the integrity of the system and that no further actions were required. The applicant identified that this experience demonstrated that items were identified during system walkdowns and that these items were placed into the work planning system for corrective action and addressed prior to loss of intended function.
Further, the applicant stated that it identified a leak from a corroded cooler plug in an intercooler
. Although the applicant determined the leak was small enough to not affect operability of the intercooler, it noted that a larger leak could potentially affect the compressors. The applicant also stated that it identified the plug failure was likely caused by formation of a galvanic cell between the carbon steel plug and the AL6XN steel in the service water system.
The applicant further stated that a replacement plug was installed and that the plug was constructed of material compatible with the station air compressors. The applicant identified that this was an example of how system walkdowns and the corrective action process identifies and corrects issues prior to system loss of intended function.
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. 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 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 Aging Management Review Results 3-40 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.2.1.14 provides the UFSAR supplement for the Compressed Air Monitoring Program. The staff reviewed this UFSAR supplement description of the program and notes that it conforms to the recommended description for this type of program as described in SRP
-LR Table 3.3-2. The staff also notes that the applicant committed (Commitment No. 14) to ongoing implementation of the existing Compressed Air Monitoring Program for managing aging of applicable components during the period of extended operation.
The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's Compressed Air Monitoring 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). 3.0.3.1.11 One-Time Inspection Summary of Technical Information in the Application. LRA Section B.2.1.20 describes the applicant's new One
-Time Inspection Program as consistent with GALL AMP XI.M32, "One Time Inspection."  The applicant stated that the One
-Time Inspection Program will provide reasonable assurance that loss of material and cracking in a selected sample of piping, piping elements , components, steam generators, tanks, and reduction of heat transfer in heat exchanger population is not occurring or that the aging effect is occurring slowly enough to not affect a component's intended function during the period of extended operation and, therefore will not require additional aging management. The applicant also stated that the One
-Time Inspection Program will be used to confirm the effectiveness of the Water Chemistry, Fuel Oil Chemistry, and Lubricating Oil Analysis programs at mitigating the effects of aging. The applicant further stated that it will use visual and volumetric inspection techniques performed per ASME Code standards and its acceptance criteria will follow station procedures based on applicable industry and regulatory codes and standards.
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 AMP XI.M32. As discussed in the Audit Report, the staff confirmed that these elements are consistent with the corresponding elements of GALL AMP XI.M32. 
 
Aging Management Review Results 3-41 Based on its audit, 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 AMP XI.M32 and, therefore, acceptable.
Operating Experience. LRA Section B.2.1.20 summarizes operating experience related to the One-Time Inspection Program. The applicant stated examples of inspections that demonstrate its success using visual and volumetric inspection techniques to evaluate loss of material and thinning in pipes connected to the high pressure feedwater heater outlet vent valve and in the service water and moisture separator drains systems. The applicant also stated that it will apply the same techniques in its One
-Time Inspection Program and, therefore, the program will be as effective as its previous inspections in identifying aging effects in relevant systems and components. In addition, for systems that credit the One
-Time Inspection Program for aging management, the applicant reviewed Maintenance Rule and System Health reports and identified that none of the aging effects being managed by the One
-Time Inspection Program negatively impacted any of those systems' performance or caused any loss of component intended function for these systems. The applicant further stated that the overall condition of these systems with respect to the applicable aging effects, coupled with the one
-time inspections, provide sufficient confidence that implementation of the One
-Time Inspection program will effectively identify and manage degradation that could lead to failure.
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. 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 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 and, 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 notes 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 No. 20) to implement the new One
-Time Inspection Program prior to entering the period of extended operation for managing aging of applicable components.
The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's One Time Inspection Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained Aging Management Review Results 3-42 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). 3.0.3.1.12 Selective Leaching of Materials Summary of Technical Information in the Application. LRA Section B.2.1.21 describes the new Selective Leaching of Materials Program as consistent with GALL AMP XI.M33, "Selective Leaching of Materials."  The applicant stated that the Selective Leaching of Materials Program ensures the integrity of components made of cast iron, bronze, brass, and other alloys exposed to raw water, brackish water, treated water, or soil environments that may lead to selective leaching of one of the metal components. The applicant also stated that the AMP includes a one-time visual inspection and hardness measurements of selected components that may be susceptible to selective leaching to identify whether material loss from selective leaching is occurring and if selective leaching will affect the ability of components to perform their intended function during the period of extended operation. The applicant further stated that aging management activities, such as periodic inspections and trending, will be implemented to manage the aging effects where selective leaching is identified.
Based upon an observation during the regional license renewal inspection, IP
-71002, the applicant amended its LRA by letter dated September 1, 2010, to include aging management activities, such as periodic inspections and trending, to manage the aging effects for material and environment combinations where selective leaching is identified.
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 AMP XI.M33. As discussed in the Audit Report, the staff confirmed that these elements are consistent with the corresponding elements of GALL AMP XI.M33. Based on its audit, the staff finds that elements one through six of the applicant's Selective Leaching of Materials Program are consistent with the corresponding program elements of GALL AMP XI.M33 and, therefore, acceptable.
Operating Experience. LRA Section B.2.1.21 summarizes operating experience related to the Selective Leaching of Materials Program. In one operating experience example, the applicant stated that de
-alloying of a service water aluminum bronze strainer drum in brackish water was identified by visual inspection during maintenance being performed on the strainer while off site.
The applicant also stated that additional examinations and evaluations were performed and that it created a routine maintenance activity for refurbishment of these components on a 6
-year frequency to ensure that the strainer drum continues to properly fulfill its intended function. The applicant further stated that this operating experience demonstrates that it has identified selective leaching and taken corrective actions to monitor and refurbish material that is susceptible to selective leaching.
In another operating experience example, the applicant stated that it identified the graphitization of gray cast iron submerged pump components from long
-term immersion in saltwater and Aging Management Review Results 3-43 brackish water environments through visual inspection of cast iron pump casing components in the circulating water system. The applicant also stated that as a consequence of the identification of this issue, inspections or refurbishment of these components are now performed
 
on a 3-year frequency. The applicant further stated that this operating experience demonstrates that it has identified selective leaching and taken corrective actions to monitor and maintain material that is susceptible to selective leaching.
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. 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 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 and, 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 notes 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 notes that the applicant committed (Commitment No. 23) to implement the new Selective Leaching of Materials Program prior to entering the period of extended operation for managing aging of applicable components
. The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's Selective Leaching of Materials Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.1.13 External Surfaces Monitoring Summary of Technical Information in the Application. LRA Section B.2.1.24 describes the new External Surfaces Monitoring Program as consistent with the program elements in GALL AMP XI.M36, "External Surfaces Monitoring."  The applicant stated that its program is a condition monitoring program that relies on observations made during visual inspections. The applicant also stated that it relies on this program to preliminarily detect occurrences of corrosion by inspecting for degradation of coatings and the appearance of visually apparent Aging Management Review Results 3-44 corrosion products on steel components. The applicant further stated that the visual inspections conducted within this program serve to detect degradation of steel components prior to any 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 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 AMP XI.M36.
As discussed in the Audit Report, the staff confirmed that these elements are consistent with the corresponding elements of GALL AMP XI.M36. Based on its audit, the staff finds that elements one through six of the applicant's External Surfaces Monitoring Program are consistent with the corresponding program elements of GALL AMP XI.M36 and, therefore, acceptable.
Operating Experience. LRA Section B.2.1.24 summarizes operating experience related to the External Surfaces Monitoring Program. In one example of operating experience, the applicant stated that during the visual inspections conducted in this program, rust was detected on carbon steel pipes due to leakage in the containment fan cooler units at Salem Unit 2 and that the corrective actions implemented included repair of the leaks. The applicant also stated that this instance of operating experience illustrates the effectiveness of the program.
In another example of operating experience, the applicant stated that it detected surface corrosion on piping associated with an evaporative cooler in Salem Unit 1 and that an engineering assessment determined the corrosion was caused by lack of insulation. The applicant also stated that it inspected other similar coolers in service at Salem Unit 1 and found that the affected Unit was not insulated equivalently to the others. The applicant further stated that the corrective actions included addition of insulation to the affected Unit and follow
-up inspections to confirm that the corrective action was effective in mitigating further corrosion.
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. 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 operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of corrosion 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. LRA Section A.2.1.24 provides the UFSAR supplement for the External Surfaces Monitoring Program. The staff reviewed this UFSAR supplement description of the program and notes 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 notes that the applicant Aging Management Review Results 3-45 committed (Commitment No. 24) to implement the new External Surfaces Monitoring Program prior to entering the period of extended operation for managing aging of applicable components.
The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's External Surfaces Monitoring 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). 3.0.3.1.14 Flux Thimble Tube Inspection Summary of Technical Information in the Application. LRA Section B.2.1.1 describes the new Flux Thimble Tube Inspection Program as consistent with GALL AMP XI.M37, "Flux Thimble Tube Inspection."  The applicant stated that the Flux Thimble Tube Inspection Program manages loss of material due to wear of the flux thimble tube materials and that it implements the recommendations of NRC Bulletin 88
-09. The applicant further stated that the program uses an inspection methodology such as eddy current testing (ECT) to inspect the flux thimble tubes on a periodic frequency to monitor wall thinning and predict when tubes will require repair or replacement. The applicant also stated that the Flux Thimble Tube Inspection Program establishes appropriate acceptance criteria (percentage through
-wall wear), based on industry guidance, and includes sufficient allowances for factors such as instrument uncertainty, uncertainties in wear scar geometry, and other potential inaccuracies applicable for the inspection methodology. The applicant stated that where the flux thimble tube through
-wall wear does not meet the established criteria, the tube must be isolated, capped, plugged, withdrawn, replaced, or otherwise removed from service in a manner that ensures the integrity of the reactor coolant pressure boundary (RCPB) is maintained.
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 with the corresponding elements of GALL AMP XI.M37. 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 AMP XI.M37, 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.
The staff noted that the applicant identified its Flux Thimble Tube Inspection Program as a "new" program because in 1993 the applicant discontinued the ECT of flux thimble tubes recommended in NRC Bulletin 88
-09, "Thimble Tube Thinning in Westinghouse Reactors."  The staff reviewed the history of the applicant's earlier Flux Thimble Tube Inspection Program, noting that in the early 1980s, the applicant experienced a number of failures in its original flux Aging Management Review Results 3-46 thimble tubes and in 1988, the applicant implemented flux thimble tube ECT in accordance with its original response to NRC Bulletin 88-09. The staff noted that in 1990, the applicant replaced all of its flux thimble tubes in Units 1 and 2 with a new, wear
-resistant thimble tube design consisting of an outer pressure boundary tube and a concentric dry guide path inner tube. The staff noted that in a letter dated December 20, 1993, the applicant submitted a supplemental response to NRC Bulletin 88
-09 providing an evaluation of the new thimble tube design and justification for discontinuing its Flux Thimble Tube Inspection Program. In a letter dated April 15, 1994 (Agencywide Document Access and Management System
[ADAMS] Accession No. ML9404220015), the staff issued a safety evaluation of the applicant's supplemental response to NRC Bulletin 88
-09 accepting the applicant's proposal to discontinue the Flux Thimble Tube Inspection Program.
During the audit, the staff asked the applicant to:  (1) clarify whether any ECT of its flux thimble tubes has been performed since issuance of the staff's safety evaluation dated April 15, 1994, (3) clarify whether any flux thimble tubes have been replaced since that date, and (3) explain how failure of a flux thimble tube's RCPB would be detected, if it should occur. In response to these questions, the applicant stated that:  (1) there have been no ECT of flux thimble tubes performed since issuance of the staff's safety evaluation; (2) some flux thimble tubes have been replaced, but not because of RCPB failure or failure caused by wear; and (3) a leak detection system monitors any leakage from flux thimble tubes, and no such leakage has been observed since replacement of the original flux thimble tubes with the improved design.
The staff noted that in GALL AMP XI.M37, the "monitoring and trending" program element states that flux thimble tube wall thickness measurements will be trended and wear rates calculated, with examination frequency based on plant
-specific wear projections, and that re-baselining of the examination frequency should be justified using plant
-specific wear
-rate data unless prior plant
-specific NRC acceptance for the re
-baselining was received. As documented in the Audit Report, the staff noted that there have been no flux thimble tube examinations during the past 16 years; however, the applicant stated that it will conduct a flux thimble tube inspection during the refueling outage prior to entering the period of extended operation to baseline the wall thickness and provide data for wear predictions. The staff noted that the applicant's statement that it will conduct a flux thimble tube inspection during the refueling outage prior to entering the period of extended operation is consistent with LRA Section A.5, "License Renewal Commitment List," Commitment No.
: 5. However, because the applicant has no current plant
-specific wear
-rate data, it was not clear to the staff how the applicant will re
-baseline its current condition of flux thimble tube wear, consistent with recommendations in GALL AMP XI.M37. By letter dated June 10, 2010, the staff issued RAI B.2.1.25-01 requesting that the applicant:  (1) explain how the baseline condition of the flux thimble tube walls will be established when ECT is reinstituted prior to entering the period of extended operation and (2) explain how plant
-specific flux thimble tube wear rates will be determined and projected to ensure that acceptance criteria for flux thimble tube wall thickness will continue to be met during the operating interval between subsequent flux thimble tube inspections.
In its response dated July 8, 2010, the applicant stated that it will prepare and approve a Flux Thimble Tube Inspection Program, consistent with LRA Appendix B, Section B.2.1.25, prior to entering the period of extended operation and that it will perform 100 percent inspection of the flux thimble tubes (58 thimbles per unit) during refueling outages in the period of extended operation using ECT or other comparable NDE in accordance with NRC Bulletin 88-09. The applicant stated that all new flux thimble tubes (using the tube
-in-tube design) were installed in December 1987 and October 1988 on Salem Uni ts 1 and 2, respectively, and that during Aging Management Review Results 3-47 August 1993, it conducted a wear evaluation of those flux thimble tubes using a combination of ECT and UT of 11 new design flux thimbles that had been removed from Salem Unit 1. The applicant further stated that its evaluation concluded that less than 3 percent wear was observed on any of the removed flux thimble tubes, which had been in service for approximately 4 years. The applicant stated that it will reestablish the baseline condition of each flux thimble tube by:  (1) taking as-found measurements over the entire length of each tube, (2) comparing the as-found measurements against the data taken on flux thimble tubes evaluated in 1993, and (3) comparing data taken in the wear region of the flux thimble tubes against data taken in the non-wear regions of the flux thimble tubes. The applicant stated that it will:  (1) measure and compare the wall thicknesses of flux thimble tube portions outside the reactor vessel (non
-wear portion) with the wall thickness of flux thimble tube portions within the lower core plate region (wear portion) and (2) include results of these measurements and comparisons to determine the baseline conditions of the flux thimble tubes.
The applicant stated that it will determine plant
-specific wear rates by comparing the as
-found wall thickness measurements taken during examination of flux thimble tubes to the wall thicknesses documented in drawings and specifications during original installation of the new flux thimbles. The applicant also stated that since the initial modification installed in 1987 and 1988, it has replaced more than 25 percent of the new flux thimble tubes in each Unit due to reasons unrelated to leakage or wear (problems with the thermocouple readings or loss of flux detector insertion capability). The applicant further stated that it will:  (1) use measurements taken on the replaced flux thimble tubes, which have varying inservice times up to approximately 20 years, to determine wear rates as a function of inservice time; (2) include comparison of wall thicknesses between non
-wear and wear portions in determining average wear rates for the flux thimble tubes; (3) project future wear for each flux thimble tube by applying the tube's estimated wear rate to its baseline condition over its inservice time; and (4) compare the projected wear and resulting predicted wall thickness loss against the acceptance criterion (nominally 70 percent of wall thickness material) to ensure that the integrity of the flux thimble tubes will be maintained during the operating interval between subsequent flux thimble tube inspections.
The staff noted that the applicant's process for reestablishing baseline conditions of the flux thimble tubes includes 100 percent of the flux thimble tubes and that it compares ECT (or comparable) wall thickness measurements of thimble tubes against both design specifications and measurements of tube thicknesses in non
-wear portions of the flux thimbles. The staff also noted that the applicant's acceptance criterion for projected wall thickness loss (70 percent of wall thickness) ensures that minimum wall thickness is maintained at least a factor of 10 greater than the maximum wear observed over a 4
-year period for thimble tubes of a similar design that the applicant examined in 1993. The staff finds the applicant's acceptance criterion adequate to ensure that integrity of the RCPB is maintained, including allowances for factors such as instrument uncertainty, uncertainties in wear scar geometry, and other potential inaccuracies.
Based on its review, the staff finds the applicant has responded acceptably to RAI B.2.1.25-01 because the methodology for reestablishing the baseline for the flux thimble tubes includes : (1) every flux thimble tube, (2) plant
-specific wear data over difference time periods, and (3) compares as measured wall thickness in tubes with both design data and as measured wall thickness in areas of the tubes that don't experience wear, and the applicant's process for determining and applying flux thimble tube wear rates is based on (1) plant
-specific measurements, (2) acceptable criteria, and (3) requires corrective actions be taken before Aging Management Review Results 3-48 unacceptable reductions in wall thickness occurs. The staff's concern described in RAI B.2.1.25-01 is resolved.
Based on its audit and review of the applicant's response to RAI B.2.1.25-01, the staff finds that elements one through six of the applicant's Flux Thimble Tube Inspection Program are consistent with the corresponding program elements of GALL AMP XI.M37 and, therefore, acceptable.
Operating Experience. LRA Section B.2.1.25 summarizes operating experience related to the Flux Thimble Tube Inspection Program. The applicant stated that the Flux Thimble Tube Inspection Program was in effect from 1985 to 1993, and it was discontinued in 1993 after the replacement of the flux thimble tubes with an alternative design and follow
-up inspections that did not find significant wear. The applicant provided three examples of its operating experience from 1981 through 1993:
The applicant stated that Salem Unit 1 replaced in
-kind all of its flux thimble tubes in 1981 after experiencing three at
-power thimble leaks, and in 1985 it performed ECT on all of the new flux thimble tubes, finding wall losses of over 50 percent for ten (10) thimble tubes. The applicant further stated that all ten thimble tubes were isolated. The applicant also stated that the possible cause was believed to be flow induced vibration at the lower core support. The applicant stated that new flux thimble tubes of an improved design were installed in 1990 to replace all of the existing tubes and inserts for the lower internals were installed to prevent flow
-induced vibration wear.
The applicant stated that Salem Unit 2 used ECT to inspect its flux thimble tubes in 1984 and that possible external damage or wall [loss] was observed on sixteen (16) tubes where they passed through the lower core support. The applicant further stated that in 1986, during the subsequent refueling outage, ECT was used and the results indicated wall losses of over 40 percent for three (3) flux thimble tubes, with these tubes subsequently being isolated. The applicant also stated that during the 1990 refueling outage, Unit 2 replaced all of its flux thimble tubes with an improved design.
The applicant stated that during the Unit 1 1993 outage, ECT was performed on eleven (11) of the improved design flux thimble tubes that had been removed and stored in the spent fuel pit. The applicant stated that the results of the ECT inspection indicated that there was no significant wear on any of the eleven flux thimble tubes, and that the indications that were found were attributed to incomplete tube cut scars and partial tube cuts. The applicant further stated that the examination indicated that no cladding bulging or ovality was detected. The applicant also stated that as a result of the examinations, Salem notified the NRC that it would discontinue future periodic inspections of flux thimble tubes.
The applicant stated that these examples demonstrate that aging effects and mechanisms were adequately managed during past implementation and that re
-implementation of the Flux Aging Management Review Results 3-49 Thimble Tube Inspection Program will effectively identify degradation prior to failure. The applicant further stated that the program will provide appropriate guidance for re
-evaluation, repair, or replacement if degradation is found.
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. 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 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 of SRP
-LR Section A.1.2.3.10 and, therefore, the staff finds it acceptable.
UFSAR Supplement. LRA Section A.2.1.25 provides the UFSAR supplement for the Flux Thimble Tube Inspection Program. The staff reviewed this UFSAR supplement description of the program and notes that it conforms to the recommended description for this type of program as described in SRP
-LR Table 3.1-2. The staff also notes that the applicant committed (Commitment No. 25) to implementing the new Flux Thimble Tube Inspection Program prior to the period of extended operation.
The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's Flux Thimble Tube Inspection Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended 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 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Summary of Technical Information in the Application. LRA Section B.2.1.26 describes the new Inspection of Internal Surfaces of Miscellaneous Piping and Ducting Components Program as consistent with GALL AMP XI.M38, "Inspection of Internal Surfaces of Miscellaneous Piping and Ducting Components."  The applicant stated that this program manages the internal surfaces of steel piping, piping components and elements, ducting components, tanks, heat exchanger components exposed to air/gas wetted, diesel exhaust, or raw water for loss of material. The applicant stated that this program includes provisions for visual inspections of the internal surfaces of components not managed under other aging management programs. The applicant also stated that inspections will be performed when internal surfaces are accessible during maintenance, surveillances, and scheduled outages. For painted or coated surfaces, the Aging Management Review Results 3-50 applicant stated that it will monitor the condition of the painted or coated finish as an indicator for corrosion of the underlying steel, and fouling to assess the effectiveness of heat exchanger components. The applicant further stated that operating history will be taken into consideration to determine the frequency of inspections and that a representative sample of locations will also be taken into consideration.
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 AMP XI.M38. As discussed in the Audit Report, the staff confirmed that these elements are consistent with the corresponding elements of GALL AMP XI.M38 with the exception of the "detection of aging effects" program element. For this element, the staff determined the need for additional clarification
. When the staff compared the LRA program description, which suggests the use of a "representative sample," to the GALL AMP XI.M38 "detection of aging effects" program element recommendations on sampling, it was unclear to the staff how the applicant defined its "representative sample" (i.e., the population criteria, size, and sampling methodology used). On August 18, 2010, the staff held a telephone conference with the applicant (ADMAS Accession Number ML102460095) to clarify the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program's sampling methodology, including how the population for each of the material
-environment
-aging effect combinations is being selected and what type of engineering, design, or operating experience considerations would be used to select the sample of components for both the scheduled and supplemental inspections. During this discussion, the applicant stated that the program will ensure that for each material, environment, and aging effect combination, representative inspections will be conducted as directed by formal preventive maintenance or recurring tasks within the work management system. The applicant also stated that the intent is to use existing preventive maintenance or recurring task activities augmented with new recurring task activities to address the inspection of material, environment, and aging effects not adequately addressed by the current activities. The applicant further stated that if adverse conditions are identified, they will be entered into a corrective action program, discussed in the LRA, and appropriate actions will be directed including identifying and evaluating the cause and extent of the condition(s). The staff finds the applicant's response acceptable and the "detection of aging effects" program element consistent with the corresponding element of GALL AMP XI.M38 because its representative sample will include inspections for each material, environment, and aging effect combinations and when degradation is found, it will be entered in the corrective action program. Based on its audit, the staff finds that elements one through six of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program are consistent with the corresponding program elements of GALL AMP XI.M38 and, therefore, acceptable.
Operating Experience. LRA Section B.2.1.26 summarizes operating experience related to the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The applicant stated that industry operating experience indicates that it is possible to sustain age-related degradation on internal surfaces of susceptible components, but that visual inspections of internal surfaces at the plant showed only minimal internal degradations. The applicant also stated the following two examples of plant operating experience which Aging Management Review Results 3-51 demonstrate the effectiveness of the relevant plant procedures on maintenance, walkdowns, and systems checks (1) an extensive maintenance history search and interviews with system managers for the ventilation systems that are within the scope of license renewal was performed and revealed no evidence of age
-related degradation and (2) review of the emergency diesel generator (EDG) turbo boost air receiver tanks and starting air receiver tanks inspections, where the applicant visually inspected the internal surfaces and probed suspect locations using UT to measure their wall thickness, was performed. Inspections performed over a 5-year period (2003
-2008) indicated that the tanks were generally clear of rust, except for a few minor rust or scaling spots which were cleaned, and follow
-up UT measurements confirmed that significant loss of material was not occurring. The applicant further stated that these examples provide objective evidence that existing maintenance activities are effective at identifying internal degradations, and any degradation is monitored and evaluated to preserve the component's intended function.
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. 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 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 and, therefore, the staff finds it acceptable.
UFSAR Supplement. LRA Section A.2.1.26 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 notes 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 notes that the applicant committed (Commitment No. 26) to implement the new Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program prior to entering the period of extended operation for managing aging of applicable components.
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). Conclusio n. On the basis of its review of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components, 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 Aging Management Review Results 3-52 concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.1.16 ASME Section XI, SubSection IWL Summary of Technical Information in the Application. LRA Section B.2.1.29 describes the existing ASME Section XI, SubSection IWL Program as consistent with GALL AMP XI.S2, "ASM E Section XI, SubSection IWL."  The applicant stated that the ASME Section XI, SubSection IWL Program implements examination requirements of ASME Code Section XI, SubSection IWL for reinforced and prestressed concrete containments (Class CC), 1998 Edition with the 1998 Addenda. The applicant further stated that the program requires periodic inspection of containment structure concrete surfaces as specified by ASME Code Section XI, SubSection IWL and approved alternatives in accordance with 10 CFR 50.55a. In addition, in response to RAI B.2.1.29-1, dated May 4, 2010, the applicant stated that prior to the period of extended operation, the program elements will be enhanced to include concrete surface examination and acceptance criteria in accordance with the guidance contained in American Concrete Institute (ACI) 349.3R. Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the enhancement the applicant submitted in response to RAI B.2.1.29-1 to determine whether the AMP, with the enhancement, is adequate to manage the aging effects for which the LRA credits it. The staff confirmed that the ASME Section XI, SubSection IWL Program contains all the elements of the referenced GALL Report program and that the plant conditions are bounded by the conditions for which the GALL Report was evaluated.
Enhancement 1. In response to RAI B.2.1.29-1, the applicant added an enhancement to the "acceptance criteria" program element in LRA Section B.2.1.29. The enhancement involves implementation of examination and acceptance criteria in accordance with the guidance contained in ACI 349.3R prior to the period of extended operation. The staff reviewed this enhancement against the corresponding program element in GALL AMP XI.S2. The staff determined that inclusion of ACI 349.3R concrete acceptance criteria in the ASME Section XI, SubSection IWL Program is acceptable because GALL AMP XI.S2 states that quantitative acceptance criteria based on the "Evaluation Criteria" provided in Chapter 5 of ACI 349.3R may also be used to augment the qualitative assessment of the responsible engineer
. Based on its review, the staff finds that elements one through six of the applicant's ASME Section XI, SubSection IWL Program, with acceptable enhancement, are consistent with the corresponding program elements of GALL AMP XI.S2 and, therefore, acceptable.
Operating Experience. LRA Section B.2.1.29 summarizes operating experience related to the ASME Section XI, SubSection IWL Program. The applicant completed a second examination of accessible concrete surfaces for the Salem Units 1 and 2 containment structures in accordance with the ASME Section XI, SubSection IWL Program in October 2005 and May 2005, respectively. The applicant stated that the examinations consisted of general visual examinations to assess the structural condition of the containment as required by IWL
-2310. The applicant stated that the degradation consisted of minor local surface scaling and spalling (less than 3 inches deep for Unit 1 and 2 inches deep for Unit 2) of concrete on exterior Aging Management Review Results 3-53 surfaces of the containment, rust stains attributed to embedded concrete inserts, localized efflorescent (leaching), and normal shrinkage cracks. The applicant also stated that examiners qualified as specified in IWL
-2310 conducted the examinations and documented the results in a corrective action report. The applicant further stated that areas of observed degradation were evaluated and accepted by the responsible engineer. The applicant concluded that this example demonstrates that loss of material (scaling and spalling) and potential reinforcing bar corrosion (rust stains) are detected and evaluated before they have impact on containment reinforced concrete structural integrity.
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. 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 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 two RAIs.
In LRA Section B.2.1.29, the applicant stated that spalling of concrete containment surfaces did not exceed a depth of 2 inches for Unit 2 and 3 inches for Unit 1 during recent inspections conducted in accordance with ASME Code Section XI, SubSection IWL. During the audit, the staff noted that these areas of observed degradation were evaluated and accepted by the responsible professional engineer based on acceptance criteria in the Salem inspection procedure S
-C-CAN-SEE-1353, Revision 0. In addition, a notification issued by the applicant describes the actual condition of the concrete on the north side of the Unit 2 containment involving surface spalling ranging up to 6 feet long and 16 inches wide
, and spalling at joints ranging up to 3 feet long and 4 inches wide. The notification also describes a condition on the north side of the Unit 2 containment between the equipment hatch and the fuel handling penetration area involving the protrusion of a pipe from the penetration wall. The notification further describes a piece of wood (1 inch by 8 inches by 4 inches) protruding from the penetration wall in the main steam area.
The staff was concerned about the extent of spalling o n the Units 1 and 2 containment exterior surface and the other issues reported in the notification issued by the applicant. Therefore, by letter dated April 15, 2010, the staff issued RAI B.2.1.29-1 requesting that the applicant (1) provide the basis for the acceptance criteria in Section 5.4 of S-C-CAN-SEE-1353, Revision 0 including the reasons for it being significantly less stringent than the ACI 349.3R requirements; (2) provide information about the broken pipe and flange protruding from the containment surface and its impact on the containment leak tightness; (3) confirm that the piece of wood (1 inch by 8 inches by 4 inches) is not embedded in the concrete containment wall; and (4) provide details of corrective actions that the applicant plans to implement for using the acceptance criteria described in Section 5.4 of S-C-CAN-SEE-1353, Revision 0 which do not conform with the current industry practice nor with ACI 349.3R. In its response dated May 13, 2010, the applicant responded to RAI B.2.1.29-1, issues (1) and (4) by stating that S-C-CAN-SEE-1353 is no longer an active document in the Salem document control system and that the ASME Section XI, SubSection IWL Program examination procedures now use the guidance provided in ACI 349.3R. The applicant initiated corrective Aging Management Review Results 3-54 actions as a result of differences between the acceptance criteria provided in Section 5.4 of S-C-CAN-SEE-1353, Revision 0, which do not conform with the current industry practice described in ACI 349.3R. The applicant stated that a visual inspection of the concrete containment
, using the ACI 349.3R tiered acceptance criteria , was done for both Salem Units 1 and 2 in April 2010. The results of the inspection were reviewed by the site responsible professional engineer and determined to satisfactorily meet all ACI 349.3R acceptance criteria.
The applicant responded to RAI B.2.1.29-1, issue (2) by stating that the broken pipe and flange reported in the notification does not protrude from the Unit 2 containment wall. The pipe is located in a wall extending outwards from the fuel handling building and has no impact on the containment leak tightness. In response to RAI B.2.1.29-1 issue (3), the applicant stated that the notification "describes a piece of wood (1 in. by 8 in. by 4 in.) that is not embedded in any concrete and is not touching the Containment. The piece of wood is wedged betw een miscellaneous steel and the mechanical penetration area wall of the Auxiliary Building, near the Containment wall. This piece of wood has no impact on containment integrity."
The staff finds the applicant's response to RAI B.2.1.29-1 acceptable because age-related degradation of concrete within the scope of ASME Code Section XI, SubSection IWL , is being managed in accordance with applicable requirements in ASME Code Section XI, SubSection IWL including an enhancement to its existing program that involves use of examination and acceptance criteria in ACI 349.3R to augment the qualitative assessment by the responsible engineer. Also the applicant stated that the less stringent concrete surface inspection criteria delineated in procedure S-C-CAN-SEE-1353 is no longer in use. In addition, the applicant has performed concrete containment inspections for both Salem Units 1 and 2 in April 2010 using the ACI 349.3R tiered acceptance criteria. Inspection results were reviewed by the site responsible professional engineer and determined to satisfactorily meet all ACI 349.3R acceptance criteria. The broken pipe and flange and piece of wood reported in the notification will not affect its leak tightness and structural integrity since these items are not connected to the Unit 2's containment. The staff concludes that this aging effect is being managed in a manner that is consistent with GALL AMP XI.S2. The staff's concern described in RAI B.2.1.29-1 is resolved.
Program element 10 for the ASME Section XI, SubSection IWL Program describes results of Units 1 and 2 containment concrete surface inspections. Physical damage to concrete surfaces and normal shrinkage cracking were observed during these inspections. The staff was concerned about the long
-term exposure of concrete cracks to salt spray originating from the Delaware Bay since it could result in corrosion of the embedded steel reinforcing bars located nearest to the outer surface of the containment concrete during the period of extended operation. Therefore, by letter dated April 15, 2010, the staff issued RAI B.2.1.29-2 requesting that the applicant describe:  (1) the extent and maximum width of the cracks observed in Salem Unit 1 and 2 containments, (2) actions that are planned to mitigate the consequences of chloride ion penetration to the level of the embedded steel reinforcing bars over the period of extended operation, and (3) an assessment of this time
-dependent phenomenon and the basis for deciding whether or not actions are anticipated to mitigate the consequences of chloride ion penetration to the level of the embedded steel reinforcing bars.
In its response to RAI B.2.1.29-2 issue (1), dated May 13, 2010, the applicant stated that concrete inspections for both Salem Units 1 and 2 containment structures were completed in April 2010 using the ACI 349.3R tiered acceptance criteria. During these inspections, pattern cracking on about a 15
-inch by 15
-inch grid with crack widths of about 0.015 inch was observed over most of the Unit 1 and 2 containment cylindrical walls and dome. However, some areas at Aging Management Review Results 3-55 the top of the dome had cracks up to 0.040 inch. In addition, cracks with widths of 0.0625 inch were observed around the Unit 2 containment air lock. The maximum crack width in the Unit 1 containment was 0.032 inch, which was observed inside the penetration area.
The applicant's responsible professional engineer reviewed the concrete surface examination results described above and found them acceptable, meeting ACI 349.3R acceptance criteria. This conclusion was based on a comparison with the cracks found during the original startup structural integrity tests. The cracks are characterized as passive and inactive. The applicant further stated that the extent of the cracking and maximum crack widths is expected and consistent with the crack patterns exhibited following the original startup structural integrity tests. Widening of cracks at the surface was identified and evaluated as part of the original structural integrity tests and accepted as a shallow, surface condition that was acceptable. In addition, during a conference call on June 30, 2010, the applicant stated that the cracks are not uniform and also reopened during subsequent integrated leak rate tests (ILRTs). Surface widening due to weathering was evident at the surface of the wider cracks. It could be seen that the cracks are narrower, less than 0.25 inch, into the concrete and considered passive. Therefore, per ACI 349.3R, no further evaluation is required. Salem will monitor and track these cracks. The staff reviewed the applicant's response concerning the extent and widths of the cracks in Unit 1 and 2 containment concrete and found it acceptable because the width of the cracks is generally about 0.015 inch and is located as expected consistent with the outer layer of reinforcing bar spacing of 15 inches. In addition, these cracks are passive and inactive. Section 5.1 of the ACI 349.3R considers passive cracks acceptable without any further evaluation. Cracks with widths of 0.040 inch in the upper part of the Unit 1 and 2 containment domes are also acceptable because the cracks are inactive and were observed during the original startup structural integrity tests. Section 5.2 of the ACI 349.3R considers inactive and passive cracks with maximum widths of 0.040 inch acceptable if inactive degradation can be determined by the quantitative comparison of current observed conditions with that of prior inspections. The 0.0625
-inch wide crack observed around the Unit 2 containment air lock is also acceptable because the crack is passive and does not extend more than 1/4 inch into the concrete. This passive and shallow crack is not likely to cause loss of monolithic behavior or corrosion of steel reinforcement. In addition, the applicant will monitor and track the cracks in the future.
In response to RAI B.2.1.29-2, issue (2), the applicant stated that the Unit 1 and 2 concrete containment surfaces were not spalled up to 3 inches, but rather had minor scaling and spalling. Therefore, there is currently no need for specific mitigative actions to prevent the potential of chloride ion penetration to the level of embedded reinforcing bars. However, if acceptance criteria specified in ACI 349.3R for spalling, scaling, and cracking cannot be met, corrective actions will be implemented. These actions may include mitigative measures, such as repairs to scaled and spalled areas of concrete and sealing of cracks to minimize penetration of chloride ions. The staff reviewed the applicant's response to RAI B.2.1.29-2, issue (2) and found it acceptable because the recent Unit 1 and 2 containment concrete surface examinations performed in April 2010 identified minor spalling and scaling. The spalling did not exceed 2 inches or extend to the depth of cover for the outer layer of reinforcing bars, and cracks are inactive and passive. Therefore, the staff agrees with the applicant's conclusion that there is no need to implement any repairs or mitigation measures at this time
.
Aging Management Review Results 3-56 In response to RAI B.2.1.29-2, issue (3), the applicant stated that the Salem containments are constructed of concrete that conforms to the applicable ACI 318 requirements. The minimum concrete clear cover over the reinforcing bars shown on the design drawings is 3
-3/8 inches nominal which is greater than the 2
-inch cover required by ACI 318 for concrete exposed to weather. Recent examinations of Unit 1 and 2 containment concrete surfaces using procedures that are based on ACI 349.3R inspection and acceptance criteria identified only minor spalling and scaling, but none that reduce the concrete cover over the reinforcing bars below the 2 inches required by ACI 318. Cracking is minor as described in the response to RAI B.2.1.29-2, issue (1). In addition, the containment concrete is observed to be free of large penetrating cracks that could permit significant chloride ion penetration to reach the level of reinforcing bars.
The applicant further stated that if chloride penetrates to the level of the reinforcing bars and initiates corrosion, the increase in volume of the steel due to the creation of rust will result in spalling, cracking, delamination of concrete, and staining of concrete surfaces. Implementation of the ASME Section XI, SubSection IWL Program described in LRA B.2.1.29 is considered to provide reasonable assurance that these aging effects will be detected and corrective actions will be taken prior to the loss of the containment intended function.
The staff reviewed the applicant's response to RAI B.2.1.29-2, issue (3) and found it acceptable because the reinforcing bars in the Unit 1 and 2 containments have a minimum clear concrete cover of 3
-3/8 inches which is greater than the 2
-inch cover required by ACI 318 for concrete exposed to weather. Visual inspection of exposed concrete surfaces for the Unit 1 and 2 containments conducted in April 2010 in accordance with the ASME Section XI, SubSection IWL Program did not identify any large penetrating active cracks that could permit significant chloride ion penetration and corrode reinforcing bars. Periodic visual inspection of Unit 1 and 2 containment concrete surfaces every 5 years as a part of the applicant's ASME Section XI, SubSection IWL Program will ensure that chloride ion penetration to the outer layer of the reinforcing bars is detected before it can adversely affect the structural integrity of the containment.
Based on its audit, review of the application, and review of the applicant's responses to RAIs B.2.1.29-1 and B.2.1.29-2, 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 and, therefore, the staff finds it acceptable.
 
Aging Management Review Results 3-57 UFSAR Supplement. LRA Section A.2.1.29 provides the UFSAR supplement for the ASME Section XI, SubSection IWL 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 3.5-2. The description includes a commitment by the applicant to perform periodic inspection of containment structure concrete surfaces using inspection methods, parameters, and acceptance criteria that are in accordance with ASME Code Section XI, SubSection IWL as approved by 10 CFR 50.55a. The applicant also committed to evaluating observed conditions that have the potential for impacting an intended function for acceptability in accordance with ASME Code Section XI, SubSection IWL requirements or corrected in accordance with the corrective action program. In addition, the applicant committed to enhance its ASME Section XI, SubSection IWL Program by including examination and acceptance criteria in accordance with guidance contained in ACI 349.3R. The staff determines that the information in the UFSAR supplement, as amended, is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusio n. On the basis of its audit and review of the applicant's ASME Section XI, SubSection IWL Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent.
The staff also reviewed the enhancement and confirmed that its implementation through Commitment No. 29 prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.1.17 ASME Section XI, SubSection IWF Summary of Technical Information in the Application. LRA Section B.2.1.30 describes the existing ASME Section XI, SubSection IWF Program as consistent with GALL AMP XI.S3, "ASME Section XI, SubSection IWF."  The applicant's ASME Section XI, SubSection IWF Program consists of periodic inspections including visual examination of Class 1, 2, and 3 piping and component supports for loss of material and loss of mechanical function in indoor air, outdoor air, air with steam or water leakage, and treated borated water environments.
Bolting for supports is also included with these components and inspected for loss of material and preload by inspecting for missing, detached, or loosened bolts and nuts. According to the applicant, the program relies on the design change procedures that are based on EPRI TR-104213 guidance to ensure proper specification of bolting material, lubricant, and installation torque. Identified degradation concerns are entered in the corrective action program for evaluation or correction to ensure the intended function of the affected component support is maintained. The applicant also stated that the program is implemented through corporate and station procedures, which provide inspection and acceptance criteria consistent with the requirements of ASME Code Section XI, SubSection IWF, 1998 Edition through the 2000 Addenda as approved in 10 CFR 50.55a. The applicant further stated that the ISI program is updated each successive 120
-month inspection interval to comply with the requirements of Aging Management Review Results 3-58 the latest edition of the ASME Code specified 12 months before the start of the inspection interval in accordance with 10 CFR 50.55a(g)(4)(ii).
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 AMP XI.S3. 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 AMP XI.S3. Based on its audit, the staff finds that elements one through six of the applicant's ASME Section XI, SubSection IWF Program are consistent with the corresponding program elements of GALL AMP XI.S3 and, therefore, acceptable.
Operating Experience. LRA Section B.2.1.30 summarizes operating experience related to the ASME Section XI, SubSection IWF Program. The first example of operating experience described by the applicant in LRA Section B.2.1.30 occurred in 2005 during inspection of Salem Unit 1. The inspection involved VT
-3 of 125 ASME Class 1, 2, and 3 component supports and was performed in accordance with ASME Code Section XI, SubSection IWF. The supports consisted of a sample of support types (i.e., anchor, guide, support, etc.) selected from the auxiliary feedwater, chemical volume control, component cooling, containment spray, reactor coolant, residual heat removal, main steam, safety injection, and service water systems. Qualified VT
-3 examiners observed no unacceptable indications on 113 of the 125 supports, but 12 supports had indications that required further evaluation. The indications on 11 supports were related to spring hanger settings that were outside acceptable tolerances. The indication on the remaining support was related to concrete cracks observed on the component cooling heater exchanger (11 CCHX) concrete pedestal support. A corrective action report was issued to document and evaluate the observed indications. Evaluation of the as
-found condition of the spring hangers prompted inspection scope increase in accordance with IWF
-2430. The scope increase resulted in additional unacceptable spring hangers. All identified spring hangers with out-of-tolerance settings were adjusted to meet design requirements and re
-examined in accordance with IWF
-3122.2. The concrete cracks on the 11 CCHX support pedestal were evaluated by engineering, determined not to impact structural integrity of the pedestal support, and accepted for continued service without repair.
The applicant stated that another VT
-3 of Salem Unit 1 was done in 2007. The inspection was performed in accordance with ASME Code Section XI, SubSection IWF and included inspection of 21 ASME Class 1, 2, and 3 component supports. The supports consist of a sample of Salem Unit 1 support types (i.e., anchor, guide, support, etc.) selected from the auxiliary feedwater, chemical volume, component cooling, containment spray, reactor coolant, residual heat removal, main steam, safety injection, and service water systems. The supports were inspected for degradation including corrosion, distortion, spring hanger functionality and settings, loose bolts and nuts, debris, and foreign material. Qualified VT
-3 examiners observed no unacceptable indications as documented in the inspection datasheet.
In 2006, the applicant conducted VT
-3 of 5 ASME Class 1, 2, and 3 component supports in accordance with ASME Code Section XI, SubSection IWF requirements at Salem Un it 2. The supports included a sample of support types (i.e., anchor, hanger, variable support, etc.)
selected from the component cooling, residual heat removal, safety injection, and main steam systems. The supports were inspected for degradation including corrosion, distortion, spring Aging Management Review Results 3-59 hanger functionality and settings, loose bolts and nuts, debris, and foreign material. Qualified VT-3 examiners observed no unacceptable indications.
During replacement of the Salem Unit 2 No. 22 steam generator in 2007, the applicant reported that two cap screws (bolts) on one of four support base plates of the steam generator support were found broken. Each support base plate has six 1
-1/2-inch diameter non
-tensioned high-strength bolts (minimum yield 200 kilopounds per square inch (ksi)). The base plate design incorporates slotted holes and Lubrite plates to allow for thermal movement. The bolts had not been previously inspected because they were not accessible. A corrective action report was initiated to document and evaluate the extent and cause of the condition. Evaluation of the condition concluded that failure was caused by improper installation and was not due to age or SCC. The bolts were not aligned as required by design to allow sliding surfaces to move without loading the bolts. The improper installation introduced high thermal loads that overstressed the two bolts causing a shear failure. As a part of extent of condition determination, the remaining bolts of both Salem Unit 2 steam generator support base plates were inspected, but no additional broken bolts were found. All the bolts on the four base plates of each Unit 2 steam generator support were replaced and installed as required by design. The applicant further stated that a past operability review determined the No. 22 steam generator was operable with the two broken bolts. Additionally, applicability of the condition to Unit 1 steam generator supports was also reviewed. The review determined the condition was not applicable to Unit 1 because of design differences between Unit 1 and Unit 2. 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 were 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 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 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 Secti on A.1.2.3.10 and, therefore, the staff finds it acceptable.
UFSAR Supplement. LRA Section A.2.1.30 provides the UFSAR supplement for the ASME Section XI, SubSection IWF Program. The staff reviewed this UFSAR supplement description of the program and notes that it conforms to the recommended description for this type of program as described in SRP
-LR Table 3.5-2. The staff also notes that the applicant committed (Commitment No. 30) to ongoing implementation of the existing ASME Section XI, SubSection IWF Program for managing aging of applicable components during the period of extended operation.
The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusio n. On the basis of its review of the applicant's ASME Section XI, SubSection IWF Program, the staff finds all program elements consistent with the GALL Report. The staff Aging Management Review Results 3-60 concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.1.18 10 CFR 50, Appendix J Summary of Technical Information in the Application. LRA Section B.2.1.31 describes the existing 10 CFR 50, Appendix J Program as consistent with GALL AMP XI.S4, "10 CFR Part 50, Appendix J."  The LRA further states that the program assures leakage through the primary containment and systems and components penetrating primary containment do not exceed allowable leakage rate limits in the TSs. The applicant further stated that the program does not prevent degradation but provides measures for monitoring to detect degradation prior to the loss of intended function. Salem is implementing Option B of the program, which allows the testing
 
intervals to be performance
-based. 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 AMP XI.S4. As discussed in the Audit Report, the staff confirmed that these elements are consistent with the corresponding elements of GALL AMP XI.S4. Based on its audit, the staff finds that elements one through six of the applicant's 10 CFR 50, Appendix J Program are consistent with the corresponding program elements of GALL AMP XI.S4 and, therefore, acceptable. Operating Experience. LRA Section B.2.1.31 summarizes operating experience related to the 10 CFR 50, Appendix J Program. The applicant provided the results of the most recent Type A ILRTs for both units. The Salem Unit 1 containment ILRT, conducted in May 2001, was performed at a pressure that slightly exceeded containment design pressure as listed in the Salem UFSAR. This Unit 1 slight overpressure was due to a procedure error that was not picked up during the peer reviews.
During the audit, the applicant provided documentation indicating no evidence of any structural damage that had been reported during subsequent ASME Section Code XI, Subsections IWE and IWL inspections. The applicant provided documentation stating that a notification was initiated to change the procedure. The due date for this change was January 18, 2007. The next ILRT is not scheduled to be performed on Salem Unit 1 until 2011. The applicant also stated that Type B and C test failures have been noted due to debris and general degradation of valve seating surfaces, which have been corrected where necessary by cleaning or adjusting the connecting components. For example, at Salem 2, the results of a local leakage rate test performed in October 2003 for an outboard isolation valve exceeded the allowable TS limits. The valve was investigated and repaired to resolve the condition. At Salem 1 in April 2001, the primary water supply to the pressurizer relief tank isolation valve was leak rate tested and found to exceed the allowable TS limits. The cause of the failure was due to the leak
-through of an adjacent valve resulting in the test failure.
Aging Management Review Results 3-61 The adjacent valve was reworked and the retest was performed satisfactorily. The extent of the condition was reviewed to determine if other failures could result from similar circumstances.
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 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.2.1.31 provides the UFSAR supplement for the 10 CFR 50, Appendix J Program. The staff reviewed this UFSAR supplement description of the program and notes that it conforms to the recommended description for this type of program as described in SRP
-LR Table 3.5-2. The staff also notes that the applicant committed (Commitment No. 31) to ongoing implementation of the existing 10 CFR 50, Appendix J Program for managing aging of applicable components during the period of extended operation.
The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's 10 CFR 50, Appendix J Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended 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). 3.0.3.1.19 Protective Coating Monitoring and Maintenance Program Summary of Technical Information in the Application. LRA Section B.2.1.35 describes the existing Protective Coating Monitoring and Maintenance Program as consistent with GALL AMP XI.S8, "Protective Coating Monitoring and Maintenance Program."  The applicant stated that the program manages cracking, blistering, flaking, peeling, and delamination of Service Level I coatings subjected to indoor air in the containment structure. The applicant's definition of Service Level I coatings, coatings used in areas in the reactor containment where the coating failure could adversely affect the operation of post
-accident fluid systems and thereby impair Aging Management Review Results 3-62 safe shutdown, is consistent with the definition of Service Level I coating defined in RG 1.54, Revision 1. 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 AMP XI.S8. As discussed in the Audit Report, the staff confirmed that these elements are consistent with the corresponding elements of GALL AMP XI.S8. Based on its audit, the staff finds that elements one through six of the applicant's Protective Coating Monitoring and Maintenance Program are consistent with the corresponding program elements of GALL AMP XI.S8 and, therefore, acceptable.
Operating Experience. LRA Section B.2.1.35 summarizes operating experience related to the Protective Coating Monitoring and Maintenance Program. The applicant included the following as part of the operating experience
: In 2008, an inspection of the Salem Unit 1 containment coatings was conducted during the refueling outage. The inspection was conducted in accordance with the Protective Coating Monitoring and Maintenance Program. Pre
-walkdown research was completed per the program requirements. While the inspections covered the accessible areas of the 78
-ft, 100-ft, and 130
-ft elevations of the containment structure outer annulus and in the bioshield, the first focused inspections were performed at areas inspected in the previous outage, and identified for continued monitoring. These areas consisted of missing coatings on the outer bioshield wall from previous efforts of removing delaminations to sound coatings, missing coatings on structural steel due to mechanical damage, and missing coatings on structural steel due to mechanical damage, and missing coatings on the concrete floor due to mechanical damage. Missing coatings identified in the previous outage and re
-inspected in the 2008 outage did not exhibit any further degradation and were considered satisfactory for the next cycle. The 2008 inspection findings indicated that the coatings applied to metal and concrete surfaces were in satisfactory condition except for two specific areas that required immediate attention in the current outage. These two areas were documented in the corrective action program and after discussions with station management on the priority for immediate corrective action, repairs were made to these areas within the current outage. This example provides objective evidence that the Protective Coating Monitoring and Maintenance Program is effective in monitoring the conditions of coatings, identifying areas of degraded conditions, recommending and communicating appropriate corrective actions, and restoring the degraded coatings to a satisfactory condition.
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. As discussed in the Audit Report, the staff conducted an independent search of the plant operating Aging Management Review Results 3-63 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 be ineffective 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 and, therefore, the staff finds it acceptable.
UFSAR Supplement. LRA Section A.2.1.35 provides the UFSAR supplement for the Protective Coating Monitoring and Maintenance Program. The staff reviewed this UFSAR supplement description of the program and notes that it conforms to the recommended description for this type of program as described in SRP
-LR Table 3.5-2. The staff also notes that the applicant committed to ongoing implementation of the existing Protective Coating Monitoring and Maintenance Program for managing aging of applicable components during the period of extended operation.
The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's Protective Coating Monitoring and Maintenance Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(2). 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).
3.0.3.1.20 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Summary of Technical Information in the Applicati on. LRA Section B.2.1.36 describes the new Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program as consistent with GALL 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 Environmental Qualification Requirements Program manages embrittlement, cracking, swelling, surface contamination, or discoloration to ensure that electrical cables, connections, and terminal blocks not subject to the EQ requirements of 10 CFR 50.49 and within the scope of license renewal are capable of performing their intended functions.
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.
 
Aging Management Review Results 3-64 The staff compared elements one through six of the applicant's program to the corresponding elements of GALL AMP XI.E1. As discussed in the Audit Report, the staff confirmed that these elements are consistent with the corresponding elements of GALL AMP XI.E1. Based on its audit, the staff finds that elements one through six of the applicant's Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program are consistent with the corresponding program elements of GALL AMP XI.E1 and, therefore, acceptable.
Operating Experience. LRA Section B.2.1.36 summarizes operating experience related to the Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program. The applicant stated that, in October 2003, mechanical technicians observed deteriorated insulation on the 230
-volt (V) cable that powers the Salem containment sump pumps. The degradation was local to the sump lid penetration and appeared to be caused by jacket embrittlement and excessive stress on the cable. The repairs to the cable insulation and jacket were made before any loss of function of the containment sump pumps was detected.
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. 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 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 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.2.1.36 provides the UFSAR supplement for the Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program. The staff reviewed this UFSAR supplement description of the program and notes that it conforms to the recommended description for this type of program as described in SRP
-LR Table 3.6-2. The staff also notes that the applicant committed (Commitment No. 36) to implement the new Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program prior to entering the period of extended operation for managing aging of applicable components.
The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements 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 Aging Management Review Results 3-65 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). 3.0.3.1.21 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.2.1.37 describes the new Electrical Cables and Connections Not Subject to 1 0 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program as consistent with GALL AMP XI.E2, "Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits."  The applicant stated that the Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program manages the in
-scope portions of the radiation monitoring system and the reactor protection system (i.e., the nuclear instrumentation system) not included in the Salem EQ program. This program applies to sensitive instrumentation cable and connection circuits with low
-level signals that are within the scope of license renewal and are located in areas where the cables and connections could be exposed to adverse localized environments caused by heat, radiation, or moisture.
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 AMP XI.E2. As discussed in the Audit Report, the staff confirmed that these elements are consistent with the corresponding elements of GALL AMP XI.E2. Based on its audit, the staff finds that elements one through six of the applicant's Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program are consistent with the corresponding program elements of GALL AMP XI.E2 and, therefore, acceptable.
Operating Experienc
: e. LRA Section B.2.1.37 summarizes operating experience related to the Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program. The applicant stated that, in December 2006, a routine surveillance of the Salem Unit 1 plant vent noble gas radiation monitor revealed a broken background detector connector. The entire detector was later replaced. The extent of the condition review revealed no other problem with the plant vent noble gas radiation monitor. The applicant also stated that, in August 2006, an investigation was initiated because the Salem Unit 1 12 steam generator blowdown radiation monitor background activity increased to above normal expected levels, although the background activity levels were still well below the alarm setpoint. The radiation monitor passed its channel source check. Further troubleshooting discovered that the cable connector between the rate meter and the pre
-amp had begun to fail. The cable and connector were replaced and the system was retested to satisfactory.
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. As discussed in the Audit Report, the staff conducted an independent search of the plant operating Aging Management Review Results 3-66 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 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 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.2.1.37 provides the UFSAR supplement for the Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program. The staff reviewed this UFSAR supplement description of the program and notes that it conforms to the recommended description for this type of program as described in SRP
-LR Table 3.6-2. The staff also notes that the applicant committed (Commitment No. 37) to implement the new Electrical Cables and Connections Not Subject to 10 C FR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program prior to entering the period of extended operation for managing aging of applicable components.
The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program, the staff finds all program elements 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). 3.0.3.1.22 Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Summary of Technical Information in the Application. LRA Section B.2.1.38 describes the new Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program as consistent with GALL AMP XI.E3 "Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements."  The applicant stated that its program manages inaccessible medium voltage cables that are exposed to significant moisture simultaneously with significant voltage. The applicant stated that significant moisture is defined as periodic exposure to moisture that lasts more than a few days (e.g., cable in standing water). The applicant also stated that significant voltage exposure is defined as being subject to system voltage for more than 25 percent of the time. The applicant further stated that in
-scope, non
-EQ, inaccessible medium voltage cable subject to significant moisture and voltage will be tested as part of this AMP. The applicant stated that these medium voltage cables will be tested using a test that is capable of detecting deterioration of the insulation system due to wetting, such as power factor, partial discharge, or polarization index or other Aging Management Review Results 3-67 testing that is state
-of-the-art at the time the test is performed. The applicant also stated that cable testing will be performed at least once every 10 years. The applicant further stated that the first tests will be completed prior to the period of extended operation.
The applicant stated that manholes and cable vaults will be inspected for water collection and in-scope, non
-EQ, inaccessible cables subject to significant moisture and voltage will be evaluated, so that draining or other corrective actions can be taken. The applicant also stated that the frequency of manhole and cable vault inspections for accumulated water and subsequent pumping will be based on existing practices and adjusted based on inspection results. Further, the applicant stated that the maximum time between inspections will be no more than 2 years with the first inspections completed 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 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 AMP XI.E3. 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 AMP XI.E3. Based on its audit, the staff finds that elements one through six of the applicant's Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program, are consistent with the corresponding program elements of GALL AMP XI.E3 and, therefore, acceptable Operating Experience. LRA Section B.2.1.38 summarizes operating experience related to the applicant's Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program. The applicant stated its program is a new program, which will adequately manage the localized damage and breakdown of insulation leading to electrical failure due to moisture intrusion and water trees. The applicant further stated that in response to Generic Letter 2007
-01, "Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients," dated May 7, 2007 and December 12, 2007 , Salem , has no history of failures of inaccessible or underground medium voltage cables.
The scope of this review included AC power cables rated 230 VAC to 15,000 VAC.
The LRA provided examples of operating experience that the applicant stated provided objective evidence that the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program will be effective in assuring that intended functions will be maintained consistent with the CLB for the period of extended operation. One example was the inspection of manhole SWI
-1 for the service water pump 4kV cable pull vaults performed in 2003 in response to NRC Information Notice 2002
-12. The applicant's inspection found the vault generally dry with some amount of water on the floor.
The cables were not submerged.
The applicant stated that this manhole has a drain installed which leads to the service water pipe tunnel sump. In June 2009, the applicant re
-inspected the manhole associated with service water medium voltage cables (SWI
-1) with no cable submergence noted. During the audit, the staff confirmed the applicant's inspection findings through document reviews including pictures taken during both the 2003 and 2009 applicant inspections. A second example was the detection, in May 2004, of ground water leakage that deteriorated the flexible conduit containing service water pump 4Kv cables into the Auxiliary building. This deterioration was repaired. A third example was the testing performed, in May 2003, on cable for the T2
-T4 crosstie (13.8 kV), in order to enable use of the crosstie cable during the refueling outage. This testing successfully detected leakage current that led to cable repair. Finally, in Aging Management Review Results 3-68 March 2001, inspection and testing of the 4kV power cable for the 12B circulating water pump motor identified a defective cable splice. Based on these examples, the applicant stated that detection methods exist to identify aging effects and prevent the loss of intended function, issues found were addressed and documented using the corrective action program, and that industry operating experience will be used to improve the program such that if any aging effects do occur, they would be detected prior to loss of intended function. The staff reviewed the operating experience 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 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. Further, the staff performed a search of regulatory operating experience for the period 2000 through November 2009. Data bases were searched using various key word searches and then reviewed by technical auditor staff.
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.
During the audit the staff also interviewed applicant personnel and reviewed documentation for in-scope medium voltage inaccessible cables associated with station blackout (SBO) to determine whether these cables were also subject to submergence. The applicant identified
 
operating experience of inaccessible medium voltage cable exposure to significant moisture. A review of LRA B.2.1.38 and the applicant's basis document did not provide operating experience for in
-scope, inaccessible medium voltage SBO recovery cable testing or manhole/ vault inspection results. Based on the above, the staff was concerned that the applicant's Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements 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.
By letter dated June 10, 2010, the staff issued RAI B.2.1.38-1 requesting the applicant to describe how LRA Section B.2.1.38 meets GALL AMP XI.E3 for in
-scope, inaccessible medium voltage SBO recovery cables considering plant operating experience shows in
-scope inaccessible medium voltage cables are exposed to significant moisture for significant periods of time (more than a few days).
The staff also requested that the applicant:
Describe how plant operating experience was incorporated into AMP B.2.1.38 to minimize exposure of in
-scope, inaccessible medium voltage SBO recovery cables to significant moisture during the period of extended operation
;discuss corrective actions taken that address submerged cable conditions identified through manhole/vault inspections;and  discuss cable testing frequency and applicability that demonstrate in
-scope inaccessible medium voltage SBO recovery cable will continue to perform their intended function during the period of extended operation.
 
Aging Management Review Results 3-69 The applicant responded by letters dated July 8, 2010, and August 26, 2010 and stated; Salem LRA Appendix B, Section B.2.1.38-"Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements," is a new program that is currently in the process of being implemented at Salem.
This program includes (1) testing of in
-scope, inaccessible medium voltage cables subject to significant moisture and significant voltage and (2) inspection of cable manholes, including pumping of accumulated water, if required, as a preventive measure to minimize the potential exposure of in
-scope cables to significant moisture.
There is no direct buried medium voltage cable in
-scope for license renewal.
The applicant also stated that, prior to the period of extended operation, additional SBO recovery cable manhole and cable pit inspections will be performed and the frequency of inspections for accumulated water will be adjusted based on inspection results to ensure that the in-scope SBO recovery cables are not exposed to significant moisture. The applicant further stated that the maximum time between inspections for accumulate d water will be no longer than two years which meets the recommended frequency in GALL AMP XI.E3.
The applicant stated that the Salem AMP B.2.1.38 meets GALL AMP XI.E3 for the in
-scope SBO recovery cables because prior to the period of extended operation, cable tests will be periodically performed (not to exceed ten years) and prior to the period of extended operation, the frequency of inspections for accumulated water will be established (not to exceed two years) based on inspection results to ensure that the in
-scope SBO recovery cables are not exposed to significant moisture during the period of extended operation.
The applicant stated that there are 8 manholes and 13 cable pits where in
-scope medium voltage SBO recovery cables can be inspected for water submergence. The applicant also stated that all 8 manholes were inspected in March
, 2010. The inspections found submerged cables; the manholes were subsequently dewatered.
The condition was entered into the applicant's corrective action program.
The applicant did not identify cable defects or concrete conditions adverse to quality as a result of the manhole inspections. The applicant did state that the cover and cover support steel for manhole MH
-1 and MH-1A were found rusted but no structural degradation was noted.
The applicant also stated that the cover and cover support structure were entered into the applicant's corrective action program with repairs planned for May 2011.
Salem LRA Appendix B, Section B.2.1.38 and the responses to Generic Letter 2007
-01 did not identify failures of in
-scope inaccessible medium voltage cables.
The applicant stated that it plans to test the SBO recovery cables every three years during station power transformer outages , with the first tests planned for April 2011.
The applicant also stated that testing will continue to be conducted periodically in order to trend and characterize the SBO recovery cable insulation. The applicant further stated that the cable test frequency may be adjusted based on data trending, but the cable test frequency will not exceed 10 years.
The applicant revised LRA Section B.2.1.38 and Section A.2.1.38 to clarify inspection and test frequencies and implementation of cable testing and inspection programs, to incorporate the RAI responses and provide consistency with GALL Report AMP XI.E3. The applicant also revised LRA Table A.5 Commitment List, Line Item 38 to specifically include manhole and cable vault inspections.
 
Aging Management Review Results 3-70 The GALL Report addresses inaccessible medium
-voltage cables in AMPXI.E3, "Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.
"  The purpose of this program is to provide reasonable assurance that the intended functions of inaccessible medium
-voltage cables (2kV to 35kV) that are not subject to the environmental qualification requirements of 10 CFR 50.49 and are exposed to adverse localized environments caused by moisture while energized
, will be maintained consistent with the CLB. The application of GALL Report AMP XI.E3 to medium voltage cables by the applicant was based on the operating experience available at the time of Revision 1 of the GALL Report was developed. However, 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 operating voltages (480V to 2kV). Applicable operating experience was identified in licensee  responses to Generic Letter (GL) 2007
-01, "Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients," which included failures of power cable operating at service voltages of less than 2kV where water was considered a contributing factor. The staff has concluded, based on recently identified industry operating experience concerning the failure of inaccessible low voltage power cables (480V to 2kV) in the presence of significant moisture, that these cables may potentially experience aging-degradation.
The staff was also concerned that recent industry operating experience also shows an increasing trend in cable failures with a length of service beginning in the 6th through 10th years of operation.
In addition, recently identified industry operating experience has shown that som e NRC licensees may experience events, such as flooding or heavy rain, that subjects cables within the scope of program for GALL Report XI.E3 to significant moisture. The staff noted that the applicant's Inaccessible Medium Voltage Cables Not Subject to 1 0 CFR 50.49 Environmental Qualification Requirements program did not address inaccessible low voltage power cables.
By teleconference dated August 16, 2010, and letter dated September 7, 2010, the NRC staff discussed with the applicant the cable test and manhole/vault inspection frequencies and the inclusion of inaccessible low voltage cables into the scope of the applicant's Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program based on recent industry operating experience. During the conference call , the applicant noted that Salem has no low voltage power cables (480V to 2kV) exposed to significant moisture. The applicant stated that the only power cables exposed to significant moisture and in
-scope of license renewal are 13.8kV, 4160V, and 230V power cables. The applicant stated they would provide this assessment and supplement the LRA to revise the Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements P rogram test and inspection frequencies to 6 years and 1 year respectively.
The applicant also agreed to revise the program to include event driven inspections and to clarify that no medium voltage cables were excluded from the program due to the "significant voltage" criterion.
By letter dated October 7, 2010 the applicant supplemented LRA  Appendix A, Section A.2.1.38, Item A.5, Item 38, and Appendix B, Section B.2.1.38, to revise cable testing and cable vault inspection criteria for the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program and stated the following:
The only power cables exposed to significant moisture that are associated with systems in
-scope for license renewal are 13,800 volt, 4,160 volt and 230 volt cables. Specifically, station blackout (SBO) recovery power is 13,800 volts and Aging Management Review Results 3-71 4160 volts, and the service water pump motor power is 4,160 volts. The auxiliary power to the Salem service water intake structure auxiliary loads is 230 volts.
Therefore, as discussed with the NRC staff in reference 3, [teleconference dated August 16, 2010] there is no change in the Salem  Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements AMP scope, as the SBO recovery and service water pump motor cables are already included within the scope of the E3 program.
Although Salem does have a 460V system within scope for license renewal, the in-scope portions of the 460 V distribution system do not go underground nor are there any in
-scope portions of the 460 V system exposed to significant moisture. Therefore the 460 V cable is not subject to the E3 [Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program] program. However, the 460 V system has already appropriately been included within the scope of the Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (E1)
Program. The applicant also stated that no inaccessible power cable exposed to significant moisture was excluded from the program due to the "significant voltage" criterion. In addition
, the applicant stated there have been no underground or inaccessible low voltage power cable failures at Salem, including 230 V power cable. The applicant also stated that the cable test frequency will be established based on test results and industry operating experience with the maximum time between tests will be no longer than 6 years. Further, the applicant stated that the frequency of inspections for accumulated water will be established based on inspection results and that station procedures will direct the assessment of the cable condition as a result of rain or other event-driven occurrences. Finally, the applicant stated that as a limit on the time between inspections, the maximum time between inspections will be no more than 1 year.
Based on the information provided by the applicant
's response to RAI B.2.1.38-1 and the LRA supplement dated October 7, 2010, the staff finds that
:  (a) The applicant has appropriately evaluated the program scope with respect to inaccessible low voltage cables (480 V to 2 kV) and eliminated the criterion of "exposure to significant voltage," consistent with industry operating experience.
  (b) For Salem , the proposed 6
-year test frequency for power cable insulation testing is appropriate for the following reasons identified in the applicant's RAI response and LRA supplement: (1) the applicant has not identified any underground or inaccessible low voltage power cable failures at Salem
; (2) inaccessible power cables within scope of the program have, however, experienced exposure to significant moisture including submergence
;  (3) the frequency of testing may be increased based on test results and operating experience. This approach is consistent with the discussion of operating experience in the SRP
-LR, which states that applicants should consider future plant-specific and applicable industry operating experience for its AMPS. 
  (c) The applicant's proposed approach to inspecting manhole and cable vaults containing inaccessible in
-scope power cables is appropriate based on the plant
-specific operating experience at Salem. For example, the applicant has established recurring tasks to
 
open , inspect , and dewater manholes, cable vaults
, and cable pits, as required to Aging Management Review Results 3-72 monitor the in
-scope service water and SBO cables.
The staff notes that the applicant's inspection plans for water accumulation are designed to optimize the inspection frequency such that
: (1) in-scope inaccessible power cables are not exposed to significant moisture
, and (2) cable condition assessment as a result rain or other event driven occurrences is included. However, at a minimum, the applicant has established a maximum time between inspections of 1 year. Given that plant
-specific operating experience has identified cables exposed to significant moisture,  an increased inspection frequency with provisions to address event
-based occurrences is acceptable, provided the applicant's approach to establish the optimum frequency will continue to inform the program
's periodicity (i.e., provide feedback for changes of the inspection periodicity as appropriate).
The staff finds that, with the enhancements provided in the applicant's LRA supplement,  and with the information provided by the applicant's response to RAI B.2.1.38-1 , the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program will adequately manage the aging effects of inaccessible power cables, consistent with industry operating experienc
: e. The staff finds the program acceptable because the applicant has revised LRA Section A.2.1.38, Section A.5, and Section B.2.1.38 consistent with the guidance of SRP LRA Section A.1.2.3.10 and GALL AMP XI.E3
, such that there is reasonable assurance that inaccessible medium voltage cable subject to significant moisture will be adequately managed during the period of extended operation.
The staff's concern described in RAI B.2.1.38-1 is resolved.
Based on its audit and review of the application, and review of the applicant's response to RAI B.2.1.38-1 and LRA supplement, 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 resulted in the applicant taking corrective action. The staff also verified that the aging effects are bounded by those identified in GALL AMP XI.E3 and the more recent operating experience identified in GL 2007
-01. 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.2.1.38 provides the UFSAR supplement for the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements 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 3.6-2. By letter dated June 10, 2009, the staff issued RAI B.2.1.38-3 to request that the applicant discuss why the UFSAR summary description in LRA Section A.2.1.38, does not include definitions of significant moisture and significant voltage consistent with SRP
-LR Tabl e 3.6-2 and LRA B.2.1.38.
The applicant responded by letter dated July 8, 2010, and stated that LRA UFSAR Supplement A.2.1.38 is revised to include these definitions.
In addition, the applicant submitted an LRA supplement dated October 7, 2010, that revised LRA Section A.2.1.38 cable test and inspection frequencies and clarified the scoping of inaccessible power cables in its Aging Management Review Results 3-73 Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program. With the information provided by the applicant's RAI response and LRA supplement dated October 7, 2010, the staff finds the UFSAR supplement acceptable because the applicant
-revised UFSAR Supplement A.2.1.38 is consistent with the guidance of SRP Table 3.6-2. Based on the applicant's response to RAI B.2.1.38-3 and the LRA supplement, the staff's concern described in RAI B.2.1.38-3 is resolved.
The staff also notes that the applicant committed (Commitment No. 38) to implement the new Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program prior to entering the period of extended operation for managing aging of applicable components.
The staff determines that the information in the UFSAR supplement, as amended, is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements 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).
3.0.3.1.23 Metal Enclosed Bus Summary of Technical Information in the Application. LRA Section B.2.1.39 describes the new Metal Enclosed Bus Program as consistent with GALL AMP XI.E4, "Metal Enclosed Bus."  The applicant stated that the Metal Enclosed Bus Program manages the aging of in
-scope metal enclosed buses within the scope of license renewal so that they are capable of performing their intended functions.
The applicant also stated that internal portions of the in
-scope metal enclosed bus enclosures will be visually inspected for cracks, corrosion, foreign debris, excessive dust buildup, and evidence of moisture intrusion. Furthermore, loose bolted connections will be checked by sampling using thermography from outside of the metal enclosed bus.
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 AMP XI.E4. As discussed in the Audit Report, the staff confirmed that these elements are consistent with the corresponding elements of GALL AMP XI.E4. The staff noted that the applicant referenced two materials (aluminum and elastomer) under metal enclosed bus components to be managed by the Structures Monitoring Program. The staff reviewed and confirmed that these materials will be managed by the Structures Monitoring Program. Based on its audit, the staff finds that elements one through six of the applicant's Metal Enclosed Bus Program are consistent with the corresponding program elements of GALL AMP XI.E4 and, therefore, acceptable.
 
Aging Management Review Results 3-74 Operating Experience. LRA Section B.2.1.39 summarizes operating experience related to the Metal Enclosed Bus Program. The applicant stated that in November 1996, in response to industry experience, work orders were generated to megger and hig h-potential test the 4
-kV non-segregated metal enclosed bus duct and inspect the duct connecting the auxiliary power transformers to the 4
-kV group buses. The duct was inspected, cleaned, and in some cases caulked, principally at locations where housing bolts may have been loose on the top horizontal sections of the duct, to prevent moisture intrusion. The applicant also included enhancements to existing preventive maintenance procedures and practices to more effectively detect water intrusion and address the lessons learned from industry operating experience.
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. 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 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 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.2.1.39 provides the UFSAR supplement for the Metal Enclosed Bus Program. The staff reviewed this UFSAR supplement description of the program and notes that it conforms to the recommended description for this type of program as described in SRP
-LR Table 3.6-2. The staff also notes that the applicant committed (Commitment No.
: 39) to implement the new Metal Enclosed Bus Program prior to entering the period of extended operation for managing aging of applicable components.
The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's Metal Enclosed Bus Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that t he 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). 3.0.3.1.24 Environmental Qualification (EQ) of Electric Components Summary of Technical Information in the Application. LRA Section B.3.1.2 describes the existing Environmental Qualification (EQ) of Electric Components Program as consistent with GALL AMP X.E1, "Environmental Qualification (EQ) of Electric Components."  The applicant Aging Management Review Results 3-75 stated that the Environmental Qualification (EQ) of Electric Components Program manages the effects of thermal, radiation, and cyclic aging through the use of aging evaluations in adverse localized environments. The applicant stated that program activities establish, demonstrate, and document the level of qualification, qualified configuration, maintenance, surveillance, and replacement requirements necessary to meet 10 CFR 50.49, "Environmental Qualification of Electrical Equipment Important to Safety for Nuclear Power Plants."  The applicant further stated that qualified life is determined for equipment within the scope of the Environmental Qualification (EQ) of Electric Components Program and appropriate actions such as replacement or refurbishment, or reanalysis are taken prior to or at the end of the qualified life of the equipment so that the aging limit is not exceeded. The applicant also stated that the program ensures maintenance of the qualified life for electrical equipment within the scope of the Environmental Qualification (EQ) of Electric Components Program through the period of extended operation.
As required by 10 CFR 50.49, EQ program components not qualified for the current license term are refurbished, replaced, or have their qualification extended prior to reaching the aging limits established in the evaluations. Aging evaluations for EQ program components are TLAAs for 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 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 AMP X.E1. 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 AMP X.E1. Based on its audit, the staff finds that elements one through six of the applicant's Environmental Qualification (EQ) of Electric Components Program are consistent with the corresponding program elements of GALL AMP X.E1 and, therefore, acceptable.
Operating Experience. LRA Section B.3.1.2 summarizes operating experience related to the Environmental Qualification (EQ) of Electric Components Program. The applicant stated its program is an existing program, which implements preventive activities to ensure that the qualified life of components within the scope of the program is maintained through the period of extended operation. The applicant also stated that the effects of aging are effectively managed by objective evidence that demonstrates that aging effects and mechanisms are adequately managed.
The applicant's operating experience included improved work planning scheduling for EQ maintenance orders and improved EQ work order scheduling including improved allowances for procurement lead times and outages. The applicant stated this example demonstrates that the applicant's program identifies and incorporates corrective actions and EQ program improvement. The applicant further stated that, to evaluate EQ concerns, plant data, calculations, and the corrective action program are used, as evidenced by the applicant's revision of the EQ calculations for the centrifugal charging pumps to account for additional pump motor run time.
The staff reviewed the operating experience 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. As discussed in the Audit Report, the staff conducted an independent search of the plant operating experience information Aging Management Review Results 3-76 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 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.3.1.2 provides the UFSAR supplement for the Environmental Qualification (EQ) of Electric Components Program. The staff reviewed this UFSAR supplement description of the program and notes that, in conjunction with the TLAA UFSAR Section A.4.7, 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 also notes that the applicant committed (Commitment No. 48) to ongoing implementation of the existing Environmental Qualification (EQ) of Electric Components  Program for managing aging of applicable components during the period of extended operation.
The staff determines that the information in the UFSAR supplement, as amended, is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's Environmental Qualification (EQ) of Electric Components 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). 3.0.3.2  AMPS That Are Consistent with the GALL Report with Exceptions or Enhancements In LRA Appendix B, the applicant identified the following AMPs that were, or will be, consistent with the GALL Report, with exceptions or enhancements:
Flow-Accelerated Corrosion Bolting Integrity Closed-Cycle Cooling Water System Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Aging Management Review Results 3-77  Fire Protection Fire Water System Aboveground Steel Tanks Fuel Oil Chemistry Reactor Vessel Surveillance Buried Piping Inspection One-Time Inspection of ASME Code Class 1 Small-Bore Piping Lubricating Oil Analysis ASME Section XI, SubSection IWE  Masonry Wall Program Structures Monitoring Program RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Metal Fatigue of Reactor Coolant Pressure Boundary For AMPs that the applicant claimed are consistent with the GALL Report, with exceptions or enhancements, the staff performed an audit to confirm that those attributes or features of the program for which the applicant claimed consistency with the GALL Report were indeed consistent. The staff also reviewed the exceptions and enhancements to the GALL Report to determine whether they were acceptable and adequate. The results of the staff's audit and reviews are documented in the following sections.
3.0.3.2.1  Flow-Accelerated Corrosion Summary of Technical Information in the Application. LRA Section B.2.1.8 describes the existing Flow
-Accelerated Corrosion Program as consistent with GALL AMP XI.M17, "Flow-Accelerated Corrosion."  The applicant stated that the program provides for predicting, detecting, and monitoring wall thinning in piping and fittings, valve bodies, and heat exchangers due to flow-accelerated corrosion in closed
-cycle cooling water, steam, and treated water environments. The applicant also stated that the program uses analytical evaluations and periodic examinations of locations that are most susceptible to wall thinning due to flow-accelerated corrosion to predict the amount of wall thinning in pipes and fittings and feedwater heater shells. The applicant further stated that a predictive code called CHECWORKS is used to determine critical locations in piping and other components susceptible to flow
-accelerated corrosion and that the Flow
-Accelerated Corrosion Program is Aging Management Review Results 3-78 based on the EPRI guidelines in NSAC
-202L, Revision 3, "Recommendations for an Effective Flow-Accelerated Corrosion 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 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 AMP XI.M17. As discussed in the Audit Report, the staff confirmed that these elements are consistent with the corresponding elements of GALL AMP XI.M17.
The staff also reviewed the portions of the "scope of the program" and "detection of aging effects" program elements associated with the exception to determine whether the program will be adequate to manage the aging effect for which it is credited. The staff's evaluation of this exception follows.
Exception 1. LRA Section B.2.1.8 states an exception to the "scope of the program" and "detection of aging effects" program elements. GALL AMP XI.M17 recommends the use of Revision 2 of the EPRI guidance document NSAC
-202L. The applicant stated that the Flow-Accelerated Corrosion Program is based on the EPRI guidelines found in NSAC
-202L, Revision 3. In addition, the applicant provided justification for using Revision 3 with the following:
The sections of NSAC
-202L associated with the program elements were reviewed to show that Revision 2 and 3 of the guidelines are equivalent with one main difference: Revision 3 allows an additional method for determining the wear of piping components from UT inspection. This method is called the Average Band Method. This method is a derivation of the Band Method and builds upon the years of experience with the Band Method, which remains an option in NSAC-202L-R3 for determining the wear of piping components from UT inspection. As explained in N SAC-202L-R3, overly conservative methods, such as [the] Band Method, can lead to unnecessary inspections or re
-inspections. The Average Band Method provides a more realistic estimate of piping wear than the Band Method.
The staff finds this program exception acceptable because the applicant demonstrated that NSAC-202L, Revision 3 is equivalent to Revision 2, with the exception being that Revision 3 uses methods that more appropriately characterize wear of piping components using UT inspection. The use of Revision 3 is determined to be consistent with GALL AMP XI.M17.
Based on its audit, the staff finds that program elements one through six of the applicant's Flow-Accelerated Corrosion Program, with acceptable exception, are consistent with the corresponding program elements of GALL AMP XI.M17 and, therefore, acceptable.
Operating Experience. LRA Section B.2.1.8 summarizes operating experience related to the Flow-Accelerated Corrosion Program. The applicant provided the following operating experience to demonstrate that the Flow
-Accelerated Corrosion Program will be effective in Aging Management Review Results 3-79 assuring that intended functions would be maintained consistent with the CLB for the period of extended operation:
  (1) In response to industry events OE9941 and OE9632, both in 1999, which document wall thinning in feedwater heater shells due to flow
-accelerated corrosion, Salem proactively inspected a sampling of high pressure and low pressure feedwater heater shells and subsequently had to replace the Salem Unit 1 15A, B and C feedwater heater shell sections with in
-kind material in the fall of 1999. Salem issued OE11020 to document the findings. At Salem Unit 2, the 25A, B and C feedwater heater shell sections were replaced with upgraded flow
-accelerated corrosion resistant stainless steel clad shell sections in 2000, as a planned replacement. Additionally, during Salem Unit 1 refueling outages in 2004 and 2005, engineering follow
-up evaluations of the Flow
-Accelerated Corrosion Program UT data information indicated that the shell wall thickness of the 15A feedwater heater in the areas around both south and north bleed steam inlet nozzles would remain above the flow
-accelerated corrosion minimum criteria through 2008, but may not meet their minimum required thickness requirements thereafter. The corrective actions for Salem Unit 1 15A, B and C feedwater heater shell sections for the areas around both bleed steam inlet nozzles involved replacing the plate Section around the nozzles with flow
-accelerated corrosion resistant stainless steel cladding in 2008.
  (2) UT inspections in support of the Flow
-Accelerated Corrosion Program scope during the Salem Unit 1 refueling outage in 2008 identified the need to replace a 3
-inch diameter pipe bend and two elbows in the moisture separator and reheater drains system going to the 16B feedwater heater. The component was selected for inspection based on CHECWORKS results. The need for replacement of this 3
-inch pipe was further increased because of identification of external corrosion, whose informational UT examination identified that its thickness in this area was close to minimum wall thickness. UT data review and evaluation was performed in accordance with the Flow-Accelerated Corrosion Program procedure. Corrective actions completed as a result of the analyses of this event identified internal pipe wall thinning to be caused by flow-accelerated corrosion over the course of this component's life, whereas the external corrosion was due to a leaking boot in the roof penetration directly above the subject bend. This Section of the pipe, including a 3
-inch diameter pipe bend and two elbows, which were made of carbon steel, were replaced with upgraded flow
-accelerated corrosion resistant chromium
-molybdenum components during the Salem Unit 1 refueling outage in 2008.
The staff reviewed operating experience information in the application and during the audit to determine whether the applicable aging effects 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 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 be ineffective 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 Aging Management Review Results 3-80 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.2.1.8 provides the UFSAR supplement for the Flow-Accelerated Corrosion Program. The staff reviewed this UFSAR supplement description of the program and notes 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. 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 Flow
-Accelerated Corrosion Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and its justification and determines that the AMP, with exception, is adequate to manage the aging effects for which the LRA credits it. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this 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  Bolting Integrity Summary of Technical Information in the Application. LRA Section B.2.1.9 describes the existing Bolting Integrity Program as consistent, with an exception and an enhancement, with GALL AMP XI.M18, "Bolting Integrity."  The applicant stated that the Bolting Integrity Program incorporates NRC and industry recommendations delineated in NUREG
-1339, "Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants"; EPRI TR-104213, "Bolted Joint Maintenance and Applications Guide"; and EPRI NP
-5769, "Degradation and Failure of Bolting in Nuclear Power Plants."  The applicant also stated that the Bolting Integrity Program provides for condition monitoring of pressure
-retaining bolting within the scope of license renewal and that the program provides for managing cracking, loss of material, and loss of preload by performing visual inspections for pressure
-retaining bolted joint leakage in environments of air, raw water, and soil. The applicant further stated that procurement controls and installation practices defined in plant procedures ensure that only approved lubricants, sealants, and proper torques are applied to bolting within the scope of the program and that the activities are implemented through station procedures.
The applicant stated that:  (1) for ASME Code class bolting, the extent and schedule of inspections is in accordance with ASME Code Section XI, Tables IWB
-2500-1, IWC-2500-1, and IWD-2500-1; (2) bolting associated with ASME Code Class 1 vessel, valve, and pump flanged joints receive VT
-1 inspection; and (3) for other pressure
-retaining bolting, routine observations will document any leakage before the leakage becomes excessive. The applicant also stated that the integrity of non
-ASME Class 1, 2, and 3 system and component pressure
-retaining bolted joints is evaluated by detection of visible leakage during maintenance or routine observation such as system walkdowns. The applicant further stated that:  (1) high
-strength Aging Management Review Results 3-81 bolting material with actual yield strength greater than or equal to 150 ksi is used for nuclear steam supply system (NSSS) Class 1 component supports, but that the bolts are installed in sliding connections with no preload to allow for thermal movement; and (2) an AMR determined that SCC is not an applicable aging effect or mechanism because the bolts are not subject to high sustained tensile stress. The applicant identified that the following AMPs supplement the aging management of bolting and fasteners:  (1)
ASME Section XI Inservice Inspection, Subsections IWB, IWC,  and IWD Program; (2)
ASME Section XI, SubSection IWE Program; (3) ASME Section XI, SubSection IWF Program; (4)
Structures Monitoring Program; (5) Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program; (6) External Surfaces Monitoring Program; (7)
Buried Piping Inspection Program; and (7)
Buried Non
-Steel Piping Inspection 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 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 AMP XI.M18. 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 AMP XI.M18, with the exception of the "scope of the program" and "preventive actions" program elements. For these elements, the staff determined the need for additional clarification that resulted in the issuance of RAIs, which are discussed below.
In GALL AMP XI.M18, the "scope of the program" program element states that the Bolting Integrity Program covers bolting within the scope of license renewal, including:  (1) safety-related bolting; (2) bolting for NSSS component supports; (3) bolting for other pressure-retaining components, including nonsafety
-related bolting; and (4) structural bolting (actual measured yield strength greater than or equal to 150 ksi). The "preventive actions" program element states that preventive actions include proper torquing and application of an appropriate preload. Based on its review of the applicant's documentation, the staff noted that aging of component support and structural bolting within the scope of license renewal may not be managed by the applicant's Bolting Integrity Program but may instead be managed by other AMPs such as the applicant's Structures Monitoring Program. It was not clear to the staff how the applicant would ensure that all elements of GALL AMP XI.M18 would be included in other AMPs credited to manage bolting not included in the Bolting Integrity Program.
By letter dated June 10, 2010, the staff issued RAI B.2.1.9-01 requesting that the applicant explain:  (1) why use of other AMPs to manage the aging effects of component support and structural bolting was not identified as an exception to the GALL AMP XI.M18 "scope of the program" program element and (2) how it ensures that other AMPs credited for aging management of component support and structural bolting include the recommendations that are contained in the GALL AMP XI.M18 "preventive actions" program element.
In its response dated July 8, 2010, the applicant confirmed its understanding that GALL AMP XI.M18 recommends that component support bolting and structural bolting be included within the scope of the Bolting Integrity Program and that the 10 elements of GALL AMP XI.M18 are applicable to component support bolting and structural bolting within the scope of license renewal. The applicant stated that it did not identify an exception to recommendations in the GALL Report because the recommendations identified in the 10 elements of GALL AMP XI.M18 are implemented through existing station procedures in its Bolting Integrity Program that are applicable to mechanical system closure bolting, as well as to component support bolting and Aging Management Review Results 3-82 structural bolting. The applicant also stated that additional AMPs credited for aging management of component support bolting and structural bolting are primarily condition monitoring programs that supplement activities of the Bolting Integrity Program. The applicant further stated that to ensure continued implementation of all 10 elements of its Bolting Integrity Program through the period of extended operation, the LRA is revised to credit the Bolting Integrity Program for component support bolting and structural bolting in the cranes and hoists system, the fuel handling and fuel storage system, the auxiliary building, the component supports commodity group, the containment structure, the fire pump house, the fuel handling building, office buildings, the penetration areas, the pipe tunnel, SBO yard buildings, service building, service water accumulator enclosures, service water intake, switchyard, turbine building, and yard structures.
In its response, the applicant provided a number of LRA changes which revised LRA Section A.2.1.9, the UFSAR supplement for the Bolting Integrity Program, and LRA Section B.2.1.9, the summary description for the Bolting Integrity Program, to describe the applicant's Bolting Integrity Program as "an existing program that provides aging management of pressure retaining bolted joints, component support bolting and structural bolting within the scope of license renewal."  The applicant also revised or added a number of bolting
-related lines in the Summary of Aging Management Evaluations tables in LRA Section 3. In the overall summary tables for each LRA subsection, the discussion for bolting components was revised to state that the Bolting Integrity Program manages aging effects in component support bolting and structural bolting and that other applicable AMPs include condition monitoring that supplements the Bolting Integrity Program. In summary tables for individual systems where the AMR result lines cited generic note E and credited some alternative to the AMP recommended in the GALL Report, the applicant added new, companion line items that credit the Bolting Integrity Program to manage the subject aging effect. For component, material, environment, and aging effect combinations that are documented in the GALL Report, the added lines are consistent with the GALL Report recommendations and cite generic note B.
In its review of the applicant's RAI response, the staff determined that including component support and structural bolting within the scope of other programs does not constitute an exception to the GALL Report because station procedures referenced in the applicant's Bolting Integrity Program that are applicable to mechanical system closure bolting are also applicable for component support bolting and structural bolting. The staff also determined that the applicant's changes to the LRA are acceptable because they clarify that alternative condition monitoring AMPs are not used in lieu of, but rather are used to supplement the mitigation and monitoring elements of the Bolting Integrity Program. The staff finds the applicant's Bolting Integrity Program to be consistent with the recommendations in GALL AMP XI.M18 with regard to the staff's concerns expressed in RAI B.2.1.9-01 and that the applicant's response resolves all issues documented in the RAI.
By letter dated May 24, 2010, the staff issued RAI 3.3.2.3.4-1, related both to the applicant's Buried Piping Inspection Program and the Bolting Integrity Program. The RAI requested that the applicant provide additional details regarding how bolting in buried piping is inspected. In its response dated June 14, 2010, the applicant stated that buried bolts are inspected during directed or opportunistic excavations of buried piping in addition to a flow test to confirm that there is no significant leakage from bolted pressure
-retaining pipe joints in accordance with its Buried Piping Inspection Program. In its evaluation of the Bolting Integrity Program, the staff finds the applicant's response to RAI 3.3.2.3.4-1 acceptable because the applicant:  (1) includes provisions for inspection of buried pressure-retaining bolting in its Buried Piping Inspection Program and (2) uses periodic flow tests to confirm that unacceptable leakage from buried, Aging Management Review Results 3-83 pressure-retaining bolted pipe joints does not occur. The staff's evaluation of the RAI response is documented in SER Section 3.3.2.3.4.
By letter dated August 3, 2010, the staff issued RAI B.2.1.9-02 requesting that the applicant:  (1) clarify what pressure joint bolting within the scope of the Bolting Integrity Program is exposed to raw water or treated borated water environments and (2) explain how visual inspections are performed to detect loss of preload for submerged bolted joints. In its response dated August 26, 2010, the applicant stated that the pressure
-retaining bolted joints exposed to raw water are limited to the service water pump bolting and that the submerged portion of the service water pumps includes bolted joints using stainless steel bolting material. The applicant further stated that the only in
-scope bolting exposed to a treated borated water environment is structural bolting in the fuel handling and fuel storage system. The applicant stated that it has no pressure
-retaining bolted joints within the scope of license renewal for which the bolting is exposed to a treated borated water environment.
The applicant stated that service water pump bolting is inspected during performance of the periodic service water pump inspection and repair procedure which is performed on a frequency of once every 6 years. The applicant further stated that during disassembly, the pumps are inspected for loose or missing bolting and the bolts are inspected for loss of material, and during reassembly, the bolting is torqued in accordance with design specifications to prevent loss of preload. In its response to RAI B.2.1.9-02, the applicant submitted changes that provide additional details in LRA Sections A.2.1.9 and B.2.1.9, the UFSAR supplement, and the program evaluation for the Bolting Integrity Program. In both LRA sections, the changes add a statement that the aging management activities directed by the Bolting Integrity Program include visual inspections for pressure
-retaining bolted joint leakage and preventive measures implemented during bolted joint maintenance and installation. In addition, in LRA Section B.2.1.9, the applicant added statements that normally inaccessible bolted connections are inspected for degradation when they are made accessible during maintenance activities and that inspection activities for submerged bolting are performed in conjunction with associated component maintenance activities. The applicant also stated that during review of information related to the RAI, it noted incorrect AMR lines in Table 3.3.2-23 for carbon steel and low
-alloy steel bolting exposed to raw water in the service water system. The applicant stated that it has determined that this bolting is not within the scope of license renewal, and the applicant provided corrections to Table 3.3.2-23 that deleted two AMR lines related to carbon and low
-alloy steel bolting exposed to raw water in the service water system.
The staff notes the applicant's clarification stating that there is no in
-scope pressure joint bolting submerged in an environment of treated borated water. The staff further notes that the applicant's aging management activities for all submerged bolting within the scope of license renewal includes inspection of the submerged bolts and bolted joints on a frequency determined by periodic maintenance or inspection of associated components. The staff finds this feature of the Bolting Integrity Program acceptable because periodic inspections provide opportunity for the applicant to find, evaluate, and correct any degraded conditions associated with submerged bolting before failure of the bolting to perform its intended function occurs. The staff also finds the applicant's changes to the LRA acceptable because they provide additional detail and clarification describing implementation of the Bolting Integrity Program and correct a previously unidentified misstatement in the LRA. On this basis, the staff finds that the applicant's response to RAI B.2.1.9-02 resolves all issues addressed in the RAI.
 
Aging Management Review Results 3-84 The staff also reviewed the portions of the "monitoring and trending" and the "corrective actions" program elements associated with the exception and the enhancement 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 and enhancement follows.
Exception. LRA Section B.2.1.9 states an exception to the "monitoring and trending" program element. The applicant stated that the GALL Report indicates that if a bolting connection for a pressure-retaining component (not covered by ASME Code Section XI) is reported to be leaking, then it may be inspected daily and that if the leak rate does not increase, the inspection frequency may be decreased to biweekly or weekly. The applicant stated that it uses its corrective action program to determine an appropriate inspection frequency for identified leaks in bolting connections.
The applicant provided justification for this exception by stating that for other than ASME Class 1, 2, or 3 bolting, it uses its corrective action program to document and manage locations where leakage is identified during routine observations, including engineering walkdowns and equipment maintenance activities. The applicant also stated that based on the severity of the leak and the potential to impact plant operations and nuclear or industrial safety, a leak will be repaired immediately, scheduled for repair, or monitored for change. The applicant further stated that if the leak rate changes (increases, decreases, or stops), the monitoring frequency is re-evaluated and may be revised and that its operating experience has not indicated a need for a set frequency (e.g., daily) of leakage inspections involving bolting.
The staff noted that the applicant's corrective action program is consistent with the requirements of 10 CFR Part 50, Appendix B and includes provisions for reporting, documenting, evaluating safety significance, trending, and implementing corrective actions for bolted pressure boundary components reported to be leaking. Because the applicant's corrective action program is consistent with 10 CFR Part 50, Appendix B and has provisions to determine an appropriate inspection frequency for a bolted pressure boundary component found to be leaking, the staff finds the applicant's exception to be acceptable.
Enhancement. LRA Section B.2.1.9 states an enhancement to the "corrective actions" program element. The applicant stated that prior to the period of extended operation, the "corrective actions" program element will be revised to state that the following bolting materials should not be reused:  (1) galvanized bolts and nuts, (2) ASTM A490 bolts, (3) any bolt and nut tightened by the turn of nut method.
The staff noted that the applicant's enhancement to its Bolting Integrity Program is listed as Commitment No.
12 in LRA Table A.5, "License Renewal Commitment List."  The staff also noted that the applicant's proposed enhancement is consistent with EPRI TR
-104213, Section 16.11.2, which provides recommendations regarding bolting material that should not be reused. On the basis that guidelines of EPRI TR
-104213 are endorsed by GALL AMP XI.M18 and the applicant's enhancement is consistent with a recommendation in the EPRI guidance document and is listed in the applicant's license renewal commitment list, the staff finds the applicant's enhancement to its Bolting Integrity Program to be acceptable.
Based on its audit and review of the applicant's response to RAI B.2.1.9-01, the staff finds that elements one through six of the applicant's Bolting Integrity program, with an acceptable exception and an enhancement, are consistent with the corresponding program elements of GALL AMP XI.M18 and, therefore, acceptable.
 
Aging Management Review Results 3-85 Operating Experience. LRA Section B.2.1.9 summarizes operating experience related to the Bolting Integrity Program. The applicant stated that it has experienced isolated cases of bolt corrosion, loss of bolt preload, and bolt torquing issues and that in all cases, the existing inspection and testing methodologies have discovered the deficiencies and corrective actions were implemented prior to loss of system or component intended functions. In one operating experience example, the applicant stated that during an 89
-13 inspection of the safety injection pump lube oil cooler, all eight studs on one of the heat exchanger end bells were found to be corroded and required replacement. The applicant also stated that the failure was caused by corrosion due to service water leaking onto the carbon steel end bell bolting and that the carbon steel bolting in contact with the titanium tubesheet and the 316 stainless steel end bell caused a severe galvanic cell when it became wetted from service water leakage. The applicant further stated that the corroded studs were replaced in
-kind and that the integrity of the bolts is controlled through proper maintenance and regular inspection.
In another operating experience example, the applicant stated that an evaluation of the torque procedure and resulting gasket preload was performed to determine whether this was the cause of leaks that occurred at the plant which identified that a change in gasket design, from asbestos to non
-asbestos replacement gaskets, was the cause of the failure because the non-asbestos gaskets require higher seating stresses to obtain an adequate seal. The applicant also stated that action was taken to incorporate EPRI bolting practices into the applicable procedures and the bolt torquing procedure was revised. The applicant further stated that these examples demonstrate that problems are discovered before intended function is affected and that corrective actions are taken to prevent recurrence.
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. 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 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 of SRP
-LR Section A.1.2.3.10 and, therefore, the staff finds it acceptable.
UFSAR Supplement. LRA Section A.2.1.9 provides the UFSAR supplement for the Bolting Integrity Program. The staff reviewed this UFSAR supplement description of the program and notes 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 No.
: 9) to enhance the Bolting Integrity Program prior to entering the period of extended operation. Specifically, the applicant committed to enhance the Bolting Integrity Program prior to the period of extended operation to include a requirement that the following bolting materials should not be used:  (1) galvanized bolts and nuts, (2) ASTM A490 bolts, (3) any bolt and nut tightened by the turn of nut method.
 
Aging Management Review Results 3-86 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 Bolting Integrity Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and its justification
 
and determines that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. Also, the staff reviewed the enhancement and confirmed that its implementation through Commitment No. 9 prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it is compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.3  Closed-Cycle Cooling Water System 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 an exception and enhancements, with GALL AMP XI.M21, "Closed
-Cycle Cooling Water System."  The applicant stated that the Closed
-Cycle Cooling Water System Program manages the aging of piping, piping components, piping elements, and heat exchangers for cracking, loss of material, and reduction in heat transfer due to fouling. The applicant stated that the program uses chemistry guidelines based on EPRI TR
-1007820 for corrosion inhibitors, water purity to mitigate corrosion, and inspections and NDEs for monitoring heat exchanger performance. The applicant also stated that the program trends the performance of system pumps and heat exchangers to identify corrective actions and indicated that a one
-time inspection will be performed in low flow areas to verify the effectiveness of the Closed
-Cycle Cooling Water System Program in mitigating aging effects in these areas.
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 AMP XI.M21. As discussed in the Audit Report, the staff confirmed that these elements are consistent with the corresponding elements of GALL AMP XI.M21. The staff also reviewed the portions of the "preventive actions," "parameters monitored or inspected," "detection of aging effects," and "monitoring and trending" program elements associated with an exception and enhancements 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 and these enhancements follows.
Exception. LRA Section B.2.1.12 states an exception to the "preventive actions," "parameters monitored or inspected," "detection of aging effects," and "monitoring and trending" program Aging Management Review Results 3-87 elements. The applicant stated that it will implement the guidance provided in EPRI TR-1007820, which is the 2004 revision to EPRI TR
-107396, whereas the GALL Report cites the 1997 revision of EPRI TR
-107396. The applicant also stated that the new revision provides more prescriptive guidance, has a more conservative monitoring approach, and meets the same requirements of EPRI TR
-107396 for effectively managing loss of material, cracking, and reduction of heat transfer.
The staff reviewed this exception to the GALL Report and noted that the applicant took the exception because the EPRI closed cooling water chemistry guidelines had been updated from the version cited in the GALL Report. The staff finds this exception acceptable because the newer version of the above EPRI guidelines contains more recent operating experience information and applies a more conservative approach to managing aging than the previous version. Enhancement 1. LRA Section B.2.1.12 states an enhancement to the "preventive actions," "detection of aging effects," and "monitoring and trending" program elements. The applicant stated that, since the component cooling system is not currently analyzed for sulfates, which is not consistent with the EPRI standard, the program will be enhanced to include monitoring for this parameter.
During the onsite audit, the staff interviewed Salem technical staff which indicated that the applicant would analyze the component cooling system for sulfates and that the frequency, method of sampling, and analysis would be consistent with EPRI guidance. On the basis of this review, the staff finds this enhancement acceptable because implementation of the EPRI guidelines has been shown to mitigate corrosion, fouling, and microbiological growth in closed cooling water systems and the applicant's program will be consistent with the recommendations in GALL AMP XI.M21, after the enhancement is implemented.
Enhancement 2. LRA Section B.2.1.12 states an enhancement to the "preventive actions," "detection of aging effects," and "monitoring and trending" program elements. The applicant stated that, since the EDG jacket water system is not currently analyzed for azole or ammonia, chlorides, fluorides, and microbiologically
-influenced corrosion (MIC) in accordance with the current EPRI standard, the program will be enhanced to include monitoring for these parameters.
During the onsite audit, the staff interviewed Salem technical staff which indicated that the applicant would analyze the EDG jacket water system for the parameters noted above and that the frequency, method of sampling, and analyses and inspections would be consistent with EPRI guidance. On the basis of its review, the staff finds this enhancement acceptable because implementation of the EPRI guidelines has been shown to mitigate corrosion, fouling, and microbiological growth in closed cooling water systems and after the enhancement is implemented, the applicant's program will be consistent with recommendations in GALL AMP XI.M21. Enhancement 3. LRA Section B.2.1.12 states an enhancement to the "preventive actions," "detection of aging effects," and "monitoring and trending" program elements. The applicant stated that the chilled water system will have a program or hardware change to bring the system chemistry parameters into compliance with EPRI TR
-1007820, prior to the period of extended operation.
 
Aging Management Review Results 3-88 During the onsite audit, the staff interviewed Salem technical staff which indicated that the chilled water system was previously managed outside the Closed
-Cycle Cooling Water System Program and that it would now be managed within that program. The applicant indicated that the program used to minimize corrosion and SCC and testing and inspection for these effects in this system would be changed to be consistent with EPRI guidance. The applicant also identified that system modifications would be performed to allow this system to be managed consistent with EPRI guidance. On the basis of its review, the staff finds this enhancement acceptable because implementation of the EPRI guidelines has been shown to mitigate corrosion, fouling, and microbiological growth in closed cooling water systems and after the enhancement is implemented, the applicant's program will be consistent with recommendations in GALL AMP XI.M21. Enhancement 4. LRA Section B.2.1.12 states an enhancement to the "parameters monitored or inspected,"
"detection of aging effects," and "monitoring and trending" program elements. The applicant stated that new recurring tasks would be established to enhance the performance monitoring of selected heat exchangers cooled by the component cooling system.
During the onsite audit, Salem technical staff indicated that since the chilled water system would now be managed within the Closed
-Cycle Cooling Water System Program, new tasks for monitoring and inspecting the heat exchangers in this system would be added to be consistent with EPRI guidance. The staff confirmed that by being consistent with EPRI guidance, it would be consistent with the recommendations of the GALL Report. On the basis of this review, the staff finds this enhancement acceptable because implementation of the EPRI guidelines has been shown to mitigate corrosion, fouling, and microbiological growth in closed cooling water systems and after the enhancement is implemented, the applicant's program will be consistent with recommendations in GALL AM P XI.M21. Enhancement 5. LRA Section B.2.1.12 states an enhancement to the "parameters monitored or inspected," "detection of aging effects," and "monitoring and trending" program elements. The applicant stated that new recurring tasks will be established for enhancing the performance monitoring of selected chilled water system components.
During the onsite audit, Salem technical staff indicated that since the chilled water system would now be managed within the Closed
-Cycle Cooling Water System Program, new recurring tasks would be needed to be consistent with EPRI guidance. On the basis of its review, the staff finds this enhancement acceptable because implementation of the EPRI guidelines has been shown to mitigate corrosion, fouling, and microbiological growth in closed cooling water systems and after the enhancement is implemented, the program will be consistent with recommendations in GALL AMP XI.M21.
Enhancement 6. LRA Section B.2.1.12 states an enhancement to the "parameters monitored or inspected," "detection of aging effects," and "monitoring and trending" program elements. The applicant stated that a one
-time inspection of selected components in stagnant flow areas will be established for selected chilled water system piping to confirm the effectiveness of the Closed-Cycle Cooling Water System Program. The applicant also stated these inspections will be performed prior to the period of extended operation.
The staff notes that effective water chemistry control can prevent some aging effects and minimize others. However, the water chemistry controls may not have always been adequate, and a one-time inspection can confirm the effectiveness of the program. On the basis of this Aging Management Review Results 3-89 review, the staff finds this enhancement acceptable because the applicant's action goes beyond the activities in the EPRI closed cooling water system guidelines, which will provide assurance that the intended function of affected components will be maintained during the period of extended operation.
Enhancement 7. LRA Section B.2.1.12 states an enhancement to the "parameters monitored or inspected," "detection of aging effects," and "acceptance criteria" program elements. The applicant stated that a one
-time inspection of selected Closed
-Cycle Cooling Water System Program components in stagnant flow areas will be conducted to confirm the effectiveness of the Closed
-Cycle Cooling Water System Program. The applicant also stated these inspections will be performed prior to the period of extended operation.
The staff notes that effective water chemistry control can prevent some aging effects and minimize others. However, locations that are isolated from the flow stream for extended periods are susceptible to gradual accumulation or concentration of agents that promote certain aging effects, and a one
-time inspection can confirm the effectiveness of the water chemistry controls. On the basis of its review, the staff finds this enhancement acceptable because the applicant's action goes beyond the activities in the EPRI closed cooling water system guidelines, which will provide assurance that the intended function of affected components will be maintained during the period of extended operation.
Enhancement 8. LRA Section B.2.1.12 states an enhancement to the "parameters monitored or inspected," "detection of aging effects," and "acceptance criteria" program elements. The applicant stated that a one
-time inspection on the interior surfaces of selected chemical mixing tanks and associated piping will be conducted to confirm the effectiveness of the Closed
-Cycle Cooling Water System Program. The applicant stated these inspections will be performed prior to the period of extended operation.
The staff notes that effective water chemistry control can prevent some aging effects an d minimize others. However, locations that are isolated from the flow stream for extended periods are susceptible to gradual accumulation or concentration of agents that promote certain aging effects, and a one
-time inspection can confirm the effectiveness of the water chemistry controls. On the basis of its review, the staff finds this enhancement acceptable because the applicant's action goes beyond the activities in the EPRI closed cooling water system guidelines and the performance of a one
-time inspection will ensure that the system mixing tanks and associated piping are able to fulfill their intended functions throughout the period of extended operation.
Enhancement 9. LRA Section B.2.1.12 states an enhancement to the "parameters monitored or inspected," "detection of aging effects," and "monitoring and trending" program elements. The applicant stated that the program will be enhanced to institute a pure water control program for the heating water and heating steam system, in accordance with EPRI T R-1007820, prior to the period of extended operation.
During the onsite audit, the staff interviewed Salem technical staff which indicated that the corrosion management of the heating water and heating steam system was transitioning to a pure water control program, which will be consistent with EPRI guidance. The staff finds this enhancement acceptable because implementation of a pure water program in accordance with EPRI guidelines has been shown to mitigate corrosion, fouling, and microbiological growth in closed cooling water systems and after the enhancement is implemented, the applicant's program will be consistent with GALL AMP XI.M21.
Aging Management Review Results 3-90 Enhancement 10. LRA Section B.2.1.12 states an enhancement to the "parameters monitored or inspected," "detection of aging effects," and "monitoring and trending" program elements. The applicant stated that new recurring tasks will be established for enhancing the performance monitoring of selected heating water and heating steam system components.
During the onsite audit, Salem technical staff indicated that since the heating water and heating steam system would now be managed as a pure water system within the Closed
-Cycle Cooling Water System Program, new tasks for performance monitoring would be added to be consisten t with EPRI guidance. On the basis of its review, the staff finds this enhancement acceptable because implementation of the EPRI guidelines has been shown to mitigate corrosion, fouling, and microbiological growth in closed cooling water systems and after the enhancement is implemented, the program will be consistent with recommendations in GALL AMP XI.M21.
Enhancement 11. LRA Section B.2.1.12 states an enhancement to the "parameters monitored or inspected," "detection of aging effects," and "monitoring and trending" program elements. The applicant stated that a one
-time inspection of selected heating water and heating steam system piping will be conducted to confirm the effectiveness of the Closed
-Cycle Cooling Water System Program. The applicant also stated these inspections will be performed prior to the period of extended operation.
The staff notes that effective water chemistry control can prevent some aging effects and minimize others. However, the water chemistry controls may not have always been adequate, and a one-time inspection can confirm the effectiveness of the program. The staff finds this enhancement acceptable because the applicant's action goes beyond the activities in the EPRI closed cooling water system guidelines and the performance of a one-time inspection of selected system piping, to confirm the effectiveness of the Closed
-Cycle Cooling Water System Program for the heating water and heating steam system, will ensure that the system piping is able to fulfill its intended functions throughout the period of extended operation.
Based on its audit, the staff finds that elements one through six of the applicant's Closed
-Cycle Cooling Water System Program, with an acceptable exception and acceptable enhancements, are consistent with the corresponding program elements of GALL AMP XI.M21 and, therefore, 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 during a self-assessment of the closed
-cycle cooling water system, it identified a trend in the occurrence of out-of-specification  potential of hydrogen (pH) and consequently identified the cause as the pH probe giving inconsistent readings. After replacing the probe with a different probe design, the applicant stated that there had been a significant reduction in the instances of pH being out of the control band, and for those cases, the program detected the excursions and restored the pH to the normal band. The applicant stated that this operating experience demonstrated that monitoring deficiencies are identified and corrective actions are properly implemented to maintain system functions.
In another instance, the applicant stated that as a result of numerous jacket water leaks on the diesel generators over the life of the plant, the station decided to change the corrosion control from chromates to a nitrite
-based control program. The applicant also stated that several years after changing to the nitrite
-based control program, technicians identified anaerobic bacteria in the jacket water of the diesel generators at levels below the limits based on EPRI guidance. The applicant stated because of this, the jacket water was changed out. The applicant stated Aging Management Review Results 3-91 that since this water change
-out, there has not been any detection of bacteria in the diesel generator jacket water. The applicant stated that this example shows the capability of the Closed-Cycle Cooling Water System Program to identify and take corrective actions to correct parameters that are outside of their 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 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 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 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 and, 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 notes 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 No.
: 12) to enhance the Closed-Cycle Cooling Water System Program prior to entering the period of extended operation. Specifically, the applicant committed to implement the following enhancements:
The component cooling system will be enhanced to include monitoring of sulfates as part of the Closed
-Cycle Cooling Water System Program The EDG jacket water will be monitored for azole or ammonia, chlorides, fluorides, and MIC consistent with current EPRI guidance.
The chilled water system will have program or hardware changes to bring the system chemistry into compliance with EPRI TR
-1007820, prior to the period of extended operation.
Enhanced performance monitoring of selected heat exchangers cooled by the component cooling system will be established.
Enhanced performance monitoring of selected components of the component cooling system will be established.
A one-time inspection of selected components of the chilled water system piping will be established to confirm the effectiveness of the Closed
-Cycle Cooling Water System Program.
Aging Management Review Results 3-92  A one-time inspection of selected stagnant flow areas of the closed cycle cooling water system will be conducted to confirm the effectiveness of the Closed
-Cycle Cooling Water System Program.
A one-time inspection of selected mixing tanks and associated piping in the closed cycle cooling water system will be conducted to confirm the effectiveness of the Closed
-Cycle Cooling Water System Program.
The heating water and heating steam system will employ a pure water control program, in accordance with EPRI TR
-1007820, prior to the period of extended operation.
New recurring tasks will be established to ensure the performance monitoring of selected heating water and heating steam components.
A one-time inspection of selected heating water and heating steam system piping will be completed to confirm the effectiveness of the Closed
-Cycle Cooling Water System Program. The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Closed
-Cycle Cooling Water System Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and its justification and determines that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. Also, the staff reviewed the enhancements and confirmed that their implementation through Commitment No.
12 prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.4  Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Summary of Technical Information in the Application. LRA Section B.2.1.13 describes the existing Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program as consistent with enhancements with GALL AMP XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems."  The applicant stated that the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program manages loss of material for all cranes, trolley, and hoist structural components (including bolting), fuel handling systems, and applicable rails that are within the scope of license renewal. The applicant also stated that visual inspections will be used to assess the aging effects of loss of material due to corrosion and visible signs of wear and loss of preload.
 
Aging Management Review Results 3-93 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 AMP XI.M23. As discussed in the Audit Report, the staff confirmed that these elements are consistent with the corresponding elements of GALL AMP XI.M23.
The staff also reviewed the portions of the "scope of the program," "detection of aging effects," and "acceptance criteria" program elements associated with the enhancements to determine whether 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 that an enhancement will be made to the "scope of the program" and "detection of aging effects" program elements. The applicant stated that this enhancement expands on the existing program element by adding visual inspection of structural components and structural bolts for loss of material due to general corrosion, pitting, and crevice corrosion and structural bolting for loss of preload due to self
-loosening. The "scope of the program" program element of GALL AMP XI.M23 states that the program manages the effects of general corrosion on the crane and trolley structural components and the effects of wear on the rails. The "detection of aging effects" program element of GALL AMP XI.M23 states that "crane rails and structural components are visually inspected on a routine basis for degradation."  The staff finds this enhancement acceptable because the enhancement related to the loss of material aging effect will make the program consistent with the recommendations in GALL AMP XI.M23 and although the loss of preload aging effect is not a specific recommendation of GALL AMP XI.M23, the aging effect can be properly managed by the applicant's Inspection of Overhead Heavy Load and Light Load (Related to Refueling)
Handling Systems Program through visual inspections and control of preload during installation and maintenance activities.
Enhancement 2. LRA Section B.2.1.13 states an enhancement to the "scope of the program" and "detection of aging effects" program elements. The applicant stated that this enhancement expands on the existing program element by adding the requirement for visual inspection of the rails and the rail system for loss of material due to wear. The "scope of the program" program element of GALL AMP XI.M23 states that the program manages the effects of wear on the rails in the rail system. The "detection of aging effects" program element of GALL AMP XI.M23 states that "crane rails and structural components are visually inspected on a routine basis for degradation."  The staff finds this enhancement acceptable because it will make the program consistent with the recommendations in GALL AMP XI.M23 and expands on the program elements to make them more specific.
Enhancement 3. LRA Section B.2.1.13 states an enhancement to the "acceptance criteria" program element. The applicant stated that this enhancement expands on the existing program element by requiring evaluation of significant loss of material due to corrosion for structural components and structural bolts and significant loss of material due to wear on the rails in the rail system. The "acceptance criteria" program element of GALL AMP XI.M23 states that "any significant visual indication of loss of material due to corrosion or wear is evaluated according to Aging Management Review Results 3-94 applicable industry standards and good industry practice."  The staff finds this enhancement acceptable because it makes the program consistent with the recommendations in GALL AMP XI.M23. Based on its audit, 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 AMP XI.M23 and, therefore, 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 no occurrences of unacceptable corrosion for components within the scope of the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program have been identified. The applicant also stated that since the applicant's cranes, hoists, trolleys, and fuel handling equipment have not been operated outside their design limits nor beyond their design lifetime, no fatigue
-related structural failures have occurred.
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. 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 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 of SRP
-LR Section A.1.2.3.10 and, therefore, the staff finds it acceptable.
UFSAR Supplement. LRA Section A.2.1.13 provides the UFSAR supplement for the Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems 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 3.3-2. The staff also notes that the applicant committed (Commitment No.
: 13) to enhance the 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 use the existing program for license renewal and to inspect for loss of material due to wear on the rails in the rail system; loss of material due to general, pitting, and crevice corrosion on structural components and bolts; and loss of preload for structural bolting and evaluation of significant loss of material due to corrosion for structural components and structural bolts and significant loss of material due to wear on the rails in the rail system.
The staff determines that the information in the UFSAR supplement, as amended, is a n adequate summary description of the program, as required by 10 CFR 54.21(d).
 
Aging Management Review Results 3-95 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 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 Commitment No.
13 prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 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  Fire Protection Summary of Technical Information in the Application. LRA Section B.2.1.15 describes the Fire Protection Program as an existing program that is consistent, with an exception and enhancements, with GALL AMP XI.M26, "Fire Protection."  The applicant stated that the program manages the effects of aging for fire barriers, the diesel fire pumps fuel oil supply lines, and the halon and carbon dioxide (CO
: 2) fire suppression systems and associated components through the use of periodic inspections and functional testing to detect aging effects prior to loss of intended functions. The applicant also stated that the program provides for:  (1) visual inspections of fire barrier penetration seals for signs of degradation (e.g., change in material properties, loss of materials, cracking, and hardening); (2) visual examinations of fire barrier walls, ceilings, and floors in structures within the scope of license renewal at a frequency of once each refueling outage; and (3) periodic visual and functional tests to manage the aging effects of fire doors and dampers and the external surfaces of the halon and CO 2 fire suppression system components. The applicant further stated that performance tests of the diesel driven fire pump will be used to detect degradation (corrosion) of the fuel supply lines before the loss of the component intended function occurs and to provide data for trending purposes. 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 AMP XI.M26. 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 AMP XI.M26, with the exception of the "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.
The "detection of aging effects" program element of GALL AMP XI.M26 recommends that visual
 
inspections of the halon and CO 2 fire suppression systems be performed to detect any sign of degradation, such as corrosion, mechanical damage, or damage to dampers, and that a periodic functional test and inspection be performed at least once every 6 months. The "acceptance criteria" program element of GALL AMP XI.M26 recommends that any sign of corrosion or mechanical damage of the halon and CO 2 fire suppression systems is not acceptable. The staff noted that the applicant's basis document for this program referenced Aging Management Review Results 3-96 procedures used to perform these functional tests and inspections. During its review of three procedures that are used to functionally test the relay room halon 1301 system, verify that valves in the flow path of the 10 ton CO 2 system are in their correct position, and verify the operation of the diesel area total flooding CO 2 system, the staff noted that there is no visual inspection activity to check for degradation, such as corrosion or mechanical damage. The staff also noted that the acceptance criteria identified in these procedures do not address corrosion. By letter dated June 10, 2010, the staff issued RAI B.2.1.15-2 requesting that the applicant confirm how this is considered consistent with GALL AMP XI.M26 and if it is not consistent, justify why this is not an exception or an enhancement.
In its response dated July 8, 2010, the applicant stated that the Fire Protection Program will be enhanced to include visual inspection activities to check for degradation during the performance
 
of halon and CO 2 fire suppression system functional tests. The evaluation of this enhancement is addressed under Enhancement 3 below.
The staff also reviewed the portions of the "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements associated with the exception and enhancements to determine whether the program will be adequate to manage the aging effects for which it is credited. The staff's evaluation of the exception and enhancements follows.
Exception. LRA Section B.2.1.15 states an exception to the "parameters monitored or inspected" and "detection of aging effects" program elements. The exception states that the halon and CO2 fire suppression systems are functionally tested every refueling cycle (18 months). The "parameters monitored or inspected" and "detection of aging effects" program elements of GALL AMP XI.M26 recommend that periodic visual inspection and functional testing be performed at least once every 6 months to examine the halon and CO2 fire suppression systems for signs of degradation.
The applicant stated that in addition to the 18
-month functional testing, the halon fire suppression system is subject to visual inspection for system charge (storage tank weight) every 6 months and the low pressure CO 2 fire suppression system is subject to a weekly visual storage tank level and pressure check. The applicant also stated that these test and inspection frequencies are considered sufficient to ensure system availability and operability based on station operating history (e.g., corrective actions, completed surveillance test results) that shows that no age
-related events have been found that have adversely affected system operation.
The staff reviewed the applicant's CLB and confirmed that functional testing of the halon and CO 2 fire suppression systems is performed once every 18 months. The staff also reviewed the plant operating experience reports and did not find any evidence of age
-related degradation in the halon or CO 2 systems. However, a review of the applicant's procedures referenced in the program basis document indicates that neither the 6 month inspection for system charge nor the weekly inspection for tank level and pressure include inspection for detecting signs of degradation such as corrosion or damper damage. Therefore, it was not clear to the staff if the exception only applied to the functional test.
By letter dated June 10, 2010, the staff issued RAI B.2.1.15-1 requesting that the applicant: 
(1) clarify whether the exception only applies to functional testing; (2) clarify whether the Fire Protection Program performs visual inspections at least once every 6 months to examine the halon and CO 2 fire suppression systems for signs of degradation; and (3) if the visual inspection is not performed once every 6 months, justify why this is not an exception to GALL AMP XI.M26.
 
Aging Management Review Results 3-97 In its response dated July 8, 2010, the applicant stated that the recommended visual inspections for corrosion or damage are performed during these system functional tests and that this exception applies to both the functional testing and the visual inspection frequency. The applicant revised the exception to state that the halon and CO 2 fire suppression systems currently undergo functional testing and inspection every refueling cycle (18 months). The staff finds the exception acceptable because plant operating experience supports that the current inspection frequency is adequate to identify the effects of aging before loss of intended function, the applicant is performing testing in accordance with its CLBs, more frequent visual inspections for system charge (storage tank weight) are performed every 6 months, and the low
-pressure CO 2 fire suppression system is subject to a weekly visual storage tank level and pressure checks. Enhancement
: 1. LRA Section B.2.1.15 states an enhancement to the "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements. In the enhancement, the applicant stated that it will expand on the existing program elements by providing additional inspection guidance to identify degradation of fire barrier walls, ceilings, and floors for aging effects, such as cracking, spalling, and loss of material caused by freeze
-thaw, chemical attack, and reaction with aggregates. The staff confirmed that the applicant included this enhancement as Commitment No.
15 in LRA Appendix A, Table A.5.
This enhancement, when implemented, will make the Fire Protection Program consistent with GALL AMP XI.M26, which recommends that visual inspection of the fire barrier walls, ceilings, and floors examines for any sign of degradation, such as cracking, spalling, and loss of material caused by freeze
-thaw, chemical attack, and reaction with aggregates. Based on its review, the staff finds the enhancement acceptable because it will make the program consistent with the GALL Report.
Enhancement 2
. LRA Section B.2.1.15 states an enhancement to the "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements to expand on the existing program elements by providing specific guidance for examining exposed external surfaces of the fire pump diesel fuel oil supply line for corrosion during pump tests. The staff confirmed that the applicant included this enhancement as Commitment No.
15 in LRA Appendix A, Table A.5. The staff notes that this enhancement, when implemented, will make the Fire Protection Program consistent with GALL AMP XI.M26, which recommends that performance of the fire pump be monitored during the periodic test to detect for any signs of degradation in the fuel supply lines, data for trending be provided, and acceptance criteria include that no corrosion is acceptable in the fuel supply line for the diesel driven fire pump. Based on its review, the staff finds the enhancement acceptable because it will make the program consistent with the GALL Report. Enhancement 3
. By letter dated July 8, 2010, the applicant added an enhancement to the "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements to expand on the existing program elements to include:  (1) visual inspections of system piping and component external surfaces for signs of corrosion or other age
-related degradation and for mechanical damage and (2) acceptance criteria stating that identified corrosion or mechanical damage will be evaluated, with corrective action taken as Aging Management Review Results 3-98 appropriate. The staff confirmed that the applicant included this enhancement in a revision to Commitment No.
15 in LRA Appendix A, Table A.5. The staff finds this enhancement acceptable because, when implemented, it will make the Fire Protection Program consistent with GALL AMP XI.M26, which recommends that visual inspections of the halon and CO 2 fire suppression systems detect for any sign of added degradation, such as corrosion, mechanical damage, or damage to dampers, and any signs of corrosion and mechanical damage of the halon and CO 2 fire suppression systems are not acceptable.
Based on its audit and review of the applicant's responses to RAIs B.2.1.15-1 and B.2.1.15
-2, the staff finds that elements one through six of the applicant's Fire Protection Program, with acceptable exception and enhancements, are consistent with the corresponding program elements of GALL AMP XI.M26 and, therefore, acceptable.
Operating Experience. LRA Section B.2.1.15 summarizes operating experience related to the Fire Protection Program. The applicant stated two examples of deficiencies identified during routine fire door inspections where the fire door failed to close and latch properly and the deficiency was repaired and retested satisfactorily. The applicant also stated that unacceptable leakage was identified coming from fire doors that where tested in preparation for full cardox concentration testing because the seal was not in complete contact with the door and doorsill, allowing gas to escape. The applicant further stated that it inspected other fire door seals for signs of degradation and replaced and adjusted the door seals to ensure proper contact between the seal and the doorsill.
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. 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 operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on fire protection system and components 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. LRA Section A.1.15 provides the UFSAR supplement for the Fire Protection Program. The staff reviewed this UFSAR supplement description of the program and notes that it conforms to the recommended description for this type of program as described in SRP-LR Table 3.3-2. The staff also notes that the applicant committed (Commitment No.
: 15) to enhance the Fire Protection Program prior to entering the period of extended operation.
Specifically, the applicant committed to:  (1) enhance the routine inspection procedures to provide additional inspection guidance to identify degradation of fire barrier walls, ceilings, and floors for aging effects such as cracking, spalling, and loss of material caused by freeze
-thaw, chemical attack, and reaction with aggregates
; (2) enhance the fire pump supply line functional tests to provide specific guidance for examining exposed external surfaces of the fire pump Aging Management Review Results 3-99 diesel fuel oil supply line for corrosion during pump tests; and (3) based on its letter dated July 8, 2010, enhance the halon and CO 2 fire suppression system functional test procedures to include visual inspection of system piping and component external surfaces for signs of corrosion or other age
-related degradation and for mechanical damage and to include acceptance criteria stating that identified corrosion or mechanical damage will be evaluated, with corrective action taken as appropriate.
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, review of the applicant's Fire Protection Program, and the applicant's response to the staff's RAIs, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the exception and its justification and determines that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. The staff also reviewed the enhancements and confirmed that their implementation through Commitment No.
15 prior to the period of extended operation will make the existing AMP consistent with the GALL Report AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging 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).
3.0.3.2.6  Fire Water System Summary of Technical Information in the Application. LRA Section B.2.1.16 describes the existing Fire Water System Program as consistent, with enhancements, with GALL AMP XI.M27, "Fire Water System."  The applicant stated that the program manages aging for the water-based fire protection systems through periodic inspections, monitoring, and performance testing. The applicant also stated that system functional tests, flow tests, flushes, and inspections are performed in accordance with the applicable guidance from National Fire Protection Association (NFPA) codes and standards. The applicant also stated that the program includes fire system main header flow tests, sprinkler system inspections, visual yard hydrant inspections, fire water storage tank inspections, fire hydrant hose inspections, hydrostatic tests, gasket inspections, volumetric inspections, fire hydrant flow tests, and pump capacity tests performed periodically to assure that the aging effect of loss of material due to corrosion, MIC, or biofouling are managed such that the system intended functions are maintained. The applicant also stated that selected portions of the fire protection system piping located aboveground and exposed to water will be inspected by non
-intrusive volumetric examinations, to ensure that aging effects are managed and that wall thickness is within acceptable limits.
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.
 
Aging Management Review Results 3-100 The staff compared elements one through six of the applicant's program to the corresponding elements of GALL AMP XI.M27. As discussed in the audit report, the staff confirmed that these elements are consistent with the corresponding elements of GALL AMP XI.M27.
The staff also reviewed the portions of the "preventive actions," "parameters monitored or inspected," "detection of aging effects," "acceptance criteria," and "corrective actions" program elements associated with the enhancements to determine whether 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 "preventive actions," "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements to expand on the existing program elements to inspect selected portions of the water
-based fire protection system piping located aboveground and exposed internally to fire water using non
-intrusive volumetric examinations. The applicant stated that these inspections shall be performed prior to the period of extended operation and every 10 years thereafter. The staff confirmed that the applicant included this enhancement as Commitment No.
16 in LRA Appendix A, Table A.5. GALL AMP XI.M27 recommends that wall thickness evaluations of fire protection piping be performed on system components using non
-intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material due to corrosion and that these inspections be performed before the end of the current operating term and at plant
-specific intervals thereafter during the period of extended operation.
The staff finds this enhancement acceptable because performing non-intrusive examinations on the aboveground fire water piping every 10 years make the program consistent with the recommendation in GALL AMP XI.M27.
Enhancement 2. LRA Section B.2.1.16 states an enhancement to the "detection of aging effects" program element to expand on the existing program element to replace or perform 50-year sprinkler head inspections and testing using the guidance of NFPA
-25, "Standard for the Inspection, Testing and Maintenance of Water
-Based Fire Protection Systems" (2002 Edition), Section 5-3.1.1. The applicant stated that these inspections will be performed by the 50-year inservice date and every 10 years thereafter. The staff confirmed that the applicant included this enhancement as Commitment No.
16 in LRA Appendix A, Table A.5. GALL AMP XI.M27 recommends that sprinkler heads are inspected before the end of the 50-year sprinkler head service life and at 10
-year intervals thereafter during the period of extended operation. The staff finds this enhancement acceptable because it will make the program consistent with the recommendation in GALL AMP XI.M27.
Based on its audit, 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 GALL AMP XI.M27 and, therefore, 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, during routine fire water system walkdowns, a small leak was found at a flow switch, which was due to a leaking gasket and seal on the switch. The applicant also stated that this flow switch was replaced and returned to service and to date, no other leaks have been found on any other flow switches on the fire water system.
 
Aging Management Review Results 3-101 The applicant stated that in February 2005, during the routine monthly fire water flow path verification, corrosion was found on the external surfaces of the fire pipe header such that paint on the 6-inch header was blistered and some of the exterior surface of the pipe could be manually removed by rubbing the surface. The applicant also stated that this degraded condition was attributed to an isolation valve packing leak located above this Section of piping and that the corrosion was only surface rust and could be easily removed. The applicant further stated that it cleaned and painted the piping and returned it to service.
The applicant stated that in February 2005, during the routine monthly fire water flow path verification walkdown, a 4
-inch wet pipe sprinkler valve was found to have surface corrosion, which was determined to have originated from a packing leak from the valve that slowly corroded the valve body over time. The applicant also stated that the valve was removed and replaced with a new valve and that, based on internal operating experience review, no further corrosion or leakage has occurred at this location. The applicant further stated that the fire protection system manager has performed visual inspections of piping internal conditions when exposed during maintenance activities, and the piping internals have been observed to be in good condition with no significant internal fouling or corrosion buildup.
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. 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 operating experience related to the applicant's program demonstrates that it can adequately manage the detrimental effects of aging on fire protection system and components 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. In LRA Section A.2.1.16, the applicant provided the UFSAR supplement for the Fire Water System Program. The staff reviewed this UFSAR supplement description of the program and notes that it conforms to the recommended description for this type of program as described in SRP
-LR Table 3.3-2. The staff notes that the applicant committed (Commitment No.
: 16) to enhance the Fire Water System Program prior to entering the period of extended operation. Specifically, the applicant committed to:  (1) enhance the program to inspect selected portions of the water
-based fire protection system piping located aboveground; these inspections shall be performed prior to the period of extended operation and will be performed every 10 years thereafter; and (2) enhance the program to replace or perform 50
-year sprinkler head inspections and testing using the guidance of NFPA
-25, "Standard for the Inspection, Testing and Maintenance of Water
-Based Fire Protection Systems" (2002 Edition), Section 5-3.1.1; these inspections will be performed prior to the 50
-year inservice date and every 10 years thereafter.
 
Aging Management Review Results 3-102 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 Fire Water System 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 Commitment No.
16 prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this A MP 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  Aboveground Steel Tanks Summary of Technical Information in the Application. LRA Section B.2.1.17 describes the existing Aboveground Steel Tanks Program as consistent, with enhancements, with GALL AMP XI.M29, "Aboveground Steel Tanks."  The applicant stated that the program will be applied to the fire protection water storage tank to manage the effects of exposure to the outdoor air and soil environment. The applicant also stated that this is a condition monitoring program and it credits the application of paint and coatings to the external surfaces of the in
-scope tanks as a corrosion prevention measure. The applicant further stated that inspections will consist of visual inspections to determine the condition of the painted or coated external surfaces, UT thickness measurements of the bottom of the tank, and visual inspection of the grout/sealant interface for degradation. The staff noted that the applicant's inspection procedures ensure that the caulk/sealant joint between the tank and foundation interface is visually inspected during the inspection of the tank.
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 AMP XI.M29. As discussed in the Audit Report, the staff confirmed that these elements are consistent with the corresponding elements of GALL AMP XI.M29.
The staff also reviewed the portions of the "preventive actions," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements associated with enhancements to determine whether 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 associated with the "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements. The program will be enhanced to require UT to obtain tank bottom thickness measurements. The applicant also stated that the thickness measurements will be evaluated against design thickness and corrosion allowance and significant degradation will be monitored and trended.
 
Aging Management Review Results 3-103 The staff evaluated this enhancement and finds it acceptable because UT provides direct, quantitative measurements of the tank bottom thickness and the applicant will evaluate results against design thickness requirements and corrosion allowance. Enhancement 2. LRA Section B.2.1.17 states an enhancement to the "preventive actions," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements. The program will be enhanced to include visual inspection of the external surfaces of the fire protection water storage tank and the grout or sealant at the interface between the tank bottom and concrete foundation.
The staff evaluated this enhancement and finds it acceptable because the applicant's routine visual inspection methods address the GALL Report recommendation for periodic system walkdowns to monitor degradation of the protective paint or coating and degradation of grout or sealant, degradation of which could result in degradation of the tank's bottom.
Based on its audit, 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 AMP XI.M29 and, therefore, acceptable.
Operating Experience. LRA Section B.2.1.17 summarizes operating experience related to the Aboveground Steel Tanks Program. The applicant stated experience in detection of corrosion on the exterior surface of a fire protection water storage tank in which degraded paint was observed during a routine visual inspection as part of this program. The applicant also stated that corrective actions were implemented which included recoating both fire protection water storage tanks, with no further negative inspection results. The applicant described another example of operating experience in which a visual inspection of an indoor fuel oil tank revealed degraded coatings which was corrected by recoating the tank. The applicant further stated that in each case discussed above, the program effectively identified the need for corrective actions and that the corrective actions were implemented prior to significant degradation or loss of material on the underlying metal tank surfaces.
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. 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 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 and, therefore, the staff finds it acceptable.
UFSAR Supplement. LRA Section A.2.1.17 provides the UFSAR supplement for the Aboveground Steel Tanks Program.
The staff reviewed this UFSAR supplement description of Aging Management Review Results 3-104 the program and notes that it conforms to the recommended description for this type of program, as described in SRP
-LR Tables 3.3-2 and 3.4-2. The staff also notes that the applicant committed (Commitment No. 17) to enhance the Aboveground Steel Tanks Program prior to entering the period of extended operation. Specifically, the applicant committed to enhance the program to include internal UT measurements to measure the wall thickness on the bottom of the tanks and conduct routine visual inspections of the tank external surfaces and grouting or sealant at the tank bottom to foundation interface.
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 Aboveground Steel Tanks Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff reviewed the enhancements and confirmed that their implementation through Commitment No.
17 prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.8  Fuel Oil Chemistry Summary of Technical Information in the Application. LRA Sectio n B.2.1.18 describes the existing Fuel Oil Chemistry Program as consistent, with exceptions and enhancements, with GALL AMP XI.M30, "Fuel Oil Chemistry."  The applicant stated that the program includes preventive activities to provide assurance that contaminants are maintained at acceptable levels in fuel oil for systems and components within the scope of license renewal to prevent loss of material. The applicant further stated that the fuel oil tanks within the scope of the program are maintained by monitoring and controlling fuel oil contaminants in accordance with ASTM standards. By periodically draining, cleaning, and inspecting the fuel oil tanks, the applicant stated that this provides reasonable assurance that potentially harmful contaminants are
 
maintained at low concentrations.
Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff also reviewed the exceptions and enhancements to determine whether the AMP, with the exceptions and enhancements, is adequate to manage the aging effects for which the LRA credits it. The staff confirmed that the Fuel Oil Chemistry Program contains all the elements of the referenced GALL Report program and that the plant conditions are bounded by the conditions for which the GALL Report was evaluated.
The staff compared program elements one through six of the applicant's program to the corresponding elements of GALL AMP XI.M30. Based on its audit, the staff finds that elements one through six of the applicant's Fuel Oil Chemistry Program are consistent with the corresponding program elements of GALL AMP XI.M30 and, therefore, acceptable.
 
Aging Management Review Results 3-105 Exception 1. LRA Section B.2.1.18 states an exception to the "scope of the program," "parameters monitored or inspected," "detection of aging effects," and "acceptance criteria" program elements. The GALL Report AMP recommends periodic sampling of tanks in accordance with manual sampling standards of ASTM D 4057
-95 (2000). The applicant stated that the 20,000
-barrel fuel oil storage tank (S1DF
-1DFE13) samples are single point samples obtained from the tank drain line located off of the bottom of the tank. This sample is not in accordance with manual sampling standards as described in ASTM D 4057. The applicant provided justification for obtaining this sample by stating that the sample results are more likely to capture contaminants, water, and sediments, thus making this a conservative sample location for fuel oil contaminants.
The staff reviewed this exception, ASTM D 4057-95, and the sampling method used by the Fuel Oil Chemistry Program. The tank bottom sampling performed by this AMP is acceptable because sampling from the tank bottom location will allow for detection of contaminants, water, and sediments, which tend to settle in the tank bottom.
The staff finds this program exception acceptable and consistent with the one described in GALL AMP XI.M30 because sampling used in the Fuel Oil Chemistry Program is equivalent or more conservative than the ASTM standard recommended by the GALL Report.
Exception 2. LRA Section B.2.1.18 states an exception to the "scope of the program," "parameters monitored or inspected," "detection of aging effects," and "acceptance criteria" program elements. The GALL Report AMP recommends periodic sampling of tanks in accordance with the manual sampling standards of ASTM D 4057
-95 (2000). The applicant stated that the 350
-gallon fire pump day tanks (S1DF
-1DFE21 and S1DF
-1DFE23) samples are single point samples obtained from the tank sight glass drain line located a few inches above the bottom of the tank. This sample is not in accordance with the manual sampling standards as described in ASTM D 4057. The applicant provided justification for obtaining this sample by stating that for fuel oil storage tanks of less than 159 cubic meters, spot sampling recommendations in ASTM D 4057 include a single sample from the middle (a distance of
 
one-half of the depth of liquid below the liquids surface). The 350
-gallon fire pump day tanks are 1.3 cubic meters, so the spot sampling recommendations in ASTM D 4057 are applicable. Although the actual sample location for the tanks is lower than prescribed by the ASTM D 4057 standard, the sample results are more likely to capture contaminants, water, and sediment, thus making this a conservative sample location for fuel oil contaminants.
The staff reviewed this exception, ASTM D 4057
-95, and the sampling method used by the Fuel Oil Chemistry Program. The single point samples obtained from the tank sight glass drain line location is acceptable because sampling from the tank bottom location will allow for detection of contaminants, water, and sediments, which tend to settle in the tank bottom.
The staff finds this program exception acceptable and consistent with the one described in GALL AMP XI.M30 because sampling used in the Fuel Oil Chemistry Program is equivalent or more conservative than the ASTM standard recommended by the GALL Report.
Exception
: 3. LRA Section B.2.1.18 states an exception to the "scope of the program," "parameters monitored or inspected," "detection of aging effects," and "acceptance criteria" program elements. The GALL Report AMP recommends periodic sampling of tanks in accordance with the manual sampling standards of ASTM D 4057
-95 (2000). The applicant stated that the 30,000
-gallon diesel fuel oil storage tanks (S1DF
-1DFE1, S1DF
-1DFE2, Aging Management Review Results 3-106 S2DF-1DFE1, and S2F
-1DFE2) samples consist of four samples drawn from two locations on the tank. One is from the level instrumentation block drain, which is located a few inches above the bottom of the tank. The remaining three samples are taken from the sump drain, which is located on the other side of the tank and is from the bottom of the tank. This sample is not in accordance with the manual sampling standards as described in ASTM D 4057. The applicant provided justification for obtaining the four samples by stating that for fuel oil storage tanks of less than 159 cubic meters, spot sampling recommendations in ASTM D 4057 include a single sample from the middle (a distance of one
-half of the depth of liquid below the liquid's surface). The 30,000
-gallon diesel fuel oil storage tanks are 113.6 cubic meters, so the spot sampling recommendations in ASTM D 4057 are applicable. Although the actual sample location for the tanks is lower than prescribed by the ASTM D 4057 standard, the sample results are more likely to capture contaminants, water, and sediment, thus making this a conservative sample location for fuel oil contaminants.
The staff reviewed this exception and ASTM D 4057
-95. The four samples obtained from the tanks level instrumentation block drain and sump drain locations are acceptable because sampling from the tank bottom location will allow for detection of contaminants, water, and sediments, which tend to settle in the tank bottom.
The staff finds this program exception acceptable and consistent with the one described in GALL AMP XI.M30 because sampling used in the Fuel Oil Chemistry Program is equivalent or more conservative than the ASTM standard recommended by the GALL Report.
Exception 4. LRA Section B.2.18 states an exception to the "scope of the program," "preventive actions," "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements. The GALL Report AMP recommends periodic sampling, draining, cleaning, and internal inspection of tanks to reduce the potential for loss of material by exposure to fuel oil contaminated with water and microbiological organisms. The applicant stated that multilevel sampling, tank bottom draining, cleaning, and internal inspection of the 550
-gallon diesel fuel oil day tanks (S1DF
-1DFE5, S2DF
-1DF3, S2DF
-1DFE4, and S2DF-1DFE5) is not periodically performed. The applicant provided justification for not performing these activities by stating that fuel oil from the 550
-gallon day tanks is recirculated to the 30,000
-gallon fuel oil storage tanks quarterly to prevent the accumulation of contaminants, water, and sediments. The diesel fuel oil day tanks are enclosed in the auxiliary building, which is maintained at a constant temperature. Maintaining a constant temperature reduces tank thermal cycling and reduces the potential for condensation formation within the tanks. In addition, the program will be enhanced to include a one
-time inspection of each of the 550-gallon day tanks prior to the period of extended operation to confirm the absence of any significant aging effects. Should the one
-time inspection reveal evidence of aging effects, the condition will be entered into the corrective action program for resolution.
The staff reviewed this exception and reviewed the performance actions recommended by the GALL Report. The recirculation of the fuel oil from the 550
-gallon day tanks accompanied with the constant temperature environment is acceptable because the potential for contaminants, water, and sediment formation at the bottom of the day tanks is reduced. The performance of a one-time inspection and the entering of adverse findings into the corrective action program were found to be acceptable.
 
Aging Management Review Results 3-107 The staff finds this program exception acceptable and consistent with the one described in GALL AMP XI.M30 because:  (1) the one
-time inspection of the tanks will allow for detection and reporting of aging effects, and (2) the recirculation of the fuel oil to the 30,000
-gallon tank, where periodic sampling for contaminants is performed, was determined to be acceptable.
Exception 5. LRA Section B.2.1.18 states an exception to the "scope of the program," "preventive actions," "parameters monitored or inspected," "monitoring and trending," and "acceptance criteria" program elements. The GALL Report AMP recommends the addition of biocides, stabilizers, and corrosion inhibitors to prevent degradation of the fuel oil quality. The applicant stated that the program does not currently include the addition of biocides, stabilizers, or corrosion inhibitors. The applicant provided justification by stating that the program will be enhanced to require the addition of biocides, stabilizers, and inhibitors if sampling or inspection activities detect the biological breakdown of the fuel or corrosion products. The applicant also stated that the program will be enhanced to include the analysis for particulate contamination in new and stored fuel oil.
The staff reviewed this exception and the recommendations found in the GALL Report AMP. The program enhancement to require the addition of biocides, stabilizers, and inhibiters if inspection activities detect the biological breakdown of the fuel or corrosion products is acceptable.
The staff finds this program exception acceptable and consistent with the one described in GALL AMP XI.M30 because an enhancement will be made to the Fuel Oil Chemistry Program to include biocides, stabilizers, and inhibitors in response to test results that indicate biological activity and biological breakdown of the fuel or corrosion products.
Enhancement 1. LRA Section B.2.1.18 states an enhancement to the "scope of the program," "preventive actions," "parameters monitored or inspected," and "detection of aging effects" program elements. This enhancement provides equivalent requirements for fuel oil purity and fuel oil testing, as described by the standard TSs.
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 AMP XI.M30.
Enhancement 2. LRA Section B.2.1.18 states an enhancement to the "scope of the program," "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements. This enhancement provides analysis for particulate contamination in accordance with modified ASTM 2276
-00 Method A. The modification consists of using a filter with a pore size of 3 microns instead of 0.8 microns.
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 AMP XI.M30.
Enhancement 3. LRA Section B.2.1.18 states an enhancement to the "scope of the program," "preventive actions," "parameters monitored or inspected," and "corrective actions" program elements. This enhancement requires the addition of biocides, stabilizers, and corrosion inhibitors as determined by fuel oil sampling or inspection activities.
 
Aging Management Review Results 3-108 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 AMP XI.M30.
Enhancement 4. LRA Section B.2.1.18 states an enhancement to the "scope of the program," "preventive actions," "parameters monitored or inspected," "detection of aging effects," and "monitoring and trending" program elements. This enhancement provides quarterly analysis for bacteria in new and stored fuel oil.
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 AMP XI.M30.
Enhancement 5. LRA Section B.2.1.18 states an enhancement to the "scope of the program," "preventive actions," "parameters monitored or inspected," and "detection of aging effects" program elements. This enhancement requires visual inspection of the internal surfaces of the
 
350-gallon fire pump day tanks (S1DF
-1DFE21 and S1DF
-1DFE23) that have been drained for cleaning and sediment removal. Ultrasonic thickness examinations of the tank bottoms are also included. 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 AMP XI.M30.
Enhancement 6. LRA Section B.2.1.18 states an enhancement to the "scope of the program," "preventive actions," "parameters monitored or inspected," "detection of aging effects," and "monitoring and trending" program elements. This enhancement provides American Petroleum Institute gravity and flash point testing of new fuel prior to unloading.
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 AMP XI.M30.
Enhancement 7. LRA Section B.2.1.18 states an enhancement to the "scope of the program," "preventive actions," "parameters monitored or inspected," and "detection of aging effects" program elements. This enhancement provides visual inspection of the internal surfaces of the diesel fuel oil storage tanks (S1DF-1DFE1, S1DF
-1DFE2, S2DF
-2DFE1, and S2DF
-2DFE2) that have been drained for cleaning and sediment removal. Ultrasonic thickness examinations of the tank bottoms are also included.
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 be make the program consistent with the recommendations in GALL AMP XI.M30.
Enhancement 8. LRA Section B.2.1.18 states an enhancement to the "scope of the program," "parameters monitored or inspected," and "detection of aging effects" program elements. This enhancement verifies the absence of any significant aging effects of each of the 550
-gallon diesel fuel oil day tanks by performing a one
-time inspection.
 
Aging Management Review Results 3-109 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 be make the program consistent with the recommendations in GALL AMP XI.M30.
Operating Experience. LRA Sectio n 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 verified that the applicant had adequately incorporated and evaluated operating experience related to this program.
The applicant provided the following for operating experience:
  (1) In 2006, a notification was written to correct the frequency of the cleaning of the 20,000 barrel main fuel oil storage tank (S1DF
-1DFE13) and the diesel fuel oil storage tanks (S1DF
-1DFE1, S1DF-1DFE2, S2DF
-1DFE1, and S2F
-1DFE2). These cleanings were previously scheduled to be done every 20 years, which was not in accordance with the industry standard of 10 years. This notification changed the frequency of the cleaning to every 10 years. Additionally, in 2008, S1DF
-1DFE1 and S1DF
-1DFE2 were cleaned and inspected and no significant degradation was found.
  (2) In July of 2005, the analysis of the 92
-day surveillance sample of the S2DF
-2DFE1 indicated that the sample failed to conform to testing specifications as defined in SC.FO-LB.ZZ-0001 for 10 percent residual carbon residue. The established specification limit is less than or equal to 0.20 percent. Testing yielded a value of 0.21 percent. A review of the other tanks (S1DF
-1DFE13, S1 DF-1DFE2, S1DF
-1DFE1, and S2DF-2DFE2) was performed and all results were satisfactory for the other tanks. The investigation of the increased value did not result in a root cause for the testing result. However, the fuel oil was determined to meet the engine manufacturer's specifications and was acceptable for use in the engines. Additionally, the review indicated that there are some variations in the test results (+/
- 0.03 percent), which could account for the reading being out of specification. Subsequent tests have indicated satisfactory results.
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. 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 be ineffective in adequately managing aging effects during the period of extended operation.
The staff confirmed that the applicant addressed operating experience identified after issuance of the GALL Report. Based on its review, 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 of SRP
-LR Section A.1.2.3.10 and, therefore, the staff finds it acceptable.
 
Aging Management Review Results 3-110 UFSAR Supplement. LRA Section A.2.1.18 provides the UFSAR supplement for the Fuel Oil Chemistry Program. The staff reviewed this UFSAR supplement description of the program and notes that it conforms to the recommended description for this type of program as described in SRP-LR Table 3.3-2. The applicant committed to enhance the Fuel Oil Chemistry Program prior to entering the period of extended operation. Specifically, the applicant committed to the following:
  (1) equivalent requirements for fuel oil purity and fuel oil testing as described by the standard TSs (2) analysis for particulate contamination in new and stored fuel oil (3) addition of biocides, stabilizers, and inhibitors as determined by fuel oil sampling or inspection activities (4) quarterly analysis for bacteria in new and stored fuel oil (5) internal inspection of the 350
-gallon fire pump day tanks (S1DF
-1DFE21 and S1DF-1DFE23) using visual inspections and ultrasonic thickness examination of tank bottoms  (6) sampling of new fuel oil deliveries for American Petroleum Institute gravity and flash point prior to offload (7) internal inspection of the 30,00 0-gallon fuel oil storage tanks (S1DF
-1DFE1, S1DF-1DFE2, S2DF
-2DFE1, and S2DF
-2DFE2) using visual inspections and ultrasonic thickness examinations of tank bottoms (8) performing a one
-time inspection of each of the 550
-gallon diesel fuel oil day tanks to confirm the absence of any significant aging effects The staff evaluated the commitments and finds them acceptable since it gives reasonable assurance that fuel oil quality will be adequately managed during the period of extended operation.
The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Fuel Oil Chemistry Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exceptions and their justifications and determines that the AMP, with 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 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).
Aging Management Review Results 3-111 3.0.3.2.9  Reactor Vessel Surveillance Summary of Technical Information in the Applicatio
: n. In LRA Section B.2.1.19, the applicant described its Reactor Vessel Surveillance Program, stating that this existing program is consistent with GALL AMP XI.M31, "Reactor Vessel Surveillance," with the following enhancements:
  (1) state the bounding RPV inlet temperature (cold leg) limits and neutron fluence projections and provide instructions for changes ("parameters monitored or inspected" program element)
  (2) describe the storage requirements and the need to retain future pulled capsules
 
("detection of aging effects" program element)
  (3) specify a scheduled date for withdrawal of capsules including pulling one of the remaining four capsules during the period of extended operation to monitor the effects of long-term exposure to neutron embrittlement for each Salem Unit ("monitoring and trending" and "acceptance criteria" program elements)
  (4) incorporate the requirements for:  (1) withdrawing the remaining capsules when the monitor capsule is withdrawn during the period of extended operation and placing them in storage for reinstituting the program if required if the RPV exposure conditions (neutron flux, spectrum, irradiation temperature, etc.) are altered and subsequently the basis for the projection to 60 years warrant the reinstitution and (2) discussing with the NRC for changes to the RPV exposure conditions and the potential need to re
-institute an RPV surveillance program ("acceptance criteria" program element)
  (5) require that if future plant operations exceed the limitations or bounds specified for cold leg temperatures (RPV inlet) or higher fluence projections, then the impact of plant operation changes on the extent of RPV embrittlement will be evaluated and the NRC shall be notified ("confirmation process" program element) With these enhancements, the applicant stated that the 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 the components within the scope of license renewal will be maintained consistent with the CLB during the period of extended operation.
Staff Evaluation. The staff reviewed the applicant's proposed Reactor Vessel Surveillance Program to confirm whether the applicant's claim of consistency with the GALL Report, with enhancements, is valid.
Appendix H of 10 CFR Part 50 specifies surveillance program criteria for 40 years of operation. GALL 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 AMP because these items, which satisfy 10 CFR Part 50, Appendix H, will stay the same throughout the period of extended operation. To ensure that all capsules in the RPV removed and tested during the period of extended operation still meet the test procedures and reporting requirements of ASTM E 185-82, "Standard Practice for Conducting Surveillance Tests for Light
-Water Cooled Aging Management Review Results 3-112 Nuclear Power Reactor Vessels," the staff imposed the following conditions to address this specific concern:
All capsules in the reactor vessel that are removed and tested must meet the test procedures and reporting requirements of ASTM E 185
-82 to the extent practicable for the configuration of the specimens in the capsule. Any changes to the capsule withdrawal schedule, including spare capsules, must be approved by the NRC prior to implementation. All capsules placed in storage must be maintained for future insertion. Any changes to storage requirements must be approved by the NRC.
The 10 CFR Part 50, Appendix H capsule withdrawal schedule during the period of extended operation is addressed according to the GALL Report's consideration of eight criteria for an acceptable RPV surveillance program for 60 years of operation.
The staff reviewed the five enhancements and the associated justifications to determine whether the Reactor Vessel Surveillance Program is adequate to manage the aging effects for which it is credited. These enhancements address four of the eight AMP acceptance criteria (Criteria 3 to 6) in GALL AMP XI.M31. Enhancement 1 is to limit the RPV cold leg temperature and neutron fluence projections. This enhancement meets the third criterion of GALL AMP XI.M31 and will increase the quality of the surveillance data. Enhancement 2 is to describe the storage requirements and the need to retain future pulled capsules. This enhancement meets the fourth criterion of GALL AMP XI.M31 and will keep used surveillance specimens for future use. Enhancement 3 is to specify capsule withdrawal schedules meeting the fifth criterion of GALL AMP XI.M31. This will provide adequate surveillance data for Salem Units 1 and 2, which have capsules with a projected neutron fluence equivalent to less than the 60-year operation for the RPV at the end of 40 years, to monitor the effects of long
-term exposure to neutron irradiation.
Enhancement 4 is to incorporate 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 meets the second part of the sixth criterion of GALL AMP XI.M31 and makes reinstituting an RPV surveillance program achievable under conditions such as change of the exposure conditions of the RPV. The first part of the sixth criterion of GALL AMP XI.M31 is for plants having capsules with a projected neutron fluence equivalent to exceeding the 60
-year operation for the RPV at the end of 40 years and is, therefore, not applicable to the applicant. Enhancement 5 is to require that if future plant operations exceed the limitations or bounds specified for cold leg temperatures (RPV inlet) or higher fluence projections, then the impact of plant operation changes on the extent of RPV embrittlement will be evaluated and the NRC shall be notified. This enhancement adequately addressed the supplemental information in GALL AMP XI.M31 related to Criteria 2 and 3 (contained in the paragraph preceding "Evaluation and Technical Basis"). Therefore, all five enhancements are needed to upgrade the existing program to be consistent with GALL AMP XI.M31. The staff's review of the Reactor Vessel Surveillance Program against the remaining three criteria is discussed below.
Criteria 1 and 2 of GALL AMP XI.M31 regard evaluation of the 60
-year upper
-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 under "Program Description" that Salem Units 1 and 2 have documented the extent of embrittlement for USE Aging Management Review Results 3-113 and P-T limits for 60 years (50 effective full-power years (EFPYs)), in accordance with RG 1.99, Revision 2, using both the chemistry tables and existing surveillance data as applicable. The program description 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 to fluence as discussed in Position 2.1 of RG 1.99, Revision
: 2. Since the Reactor Vessel Surveillance Program 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. Criterion 7 does not apply to the Reactor Vessel Surveillance Program because it is for plants not having surveillance capsules. 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, it was addressed indirectly in LRA Section 4.2.1, which indicated that the inlet and outlet nozzles for both Salem RPVs will experience 50
-EFPY fluence less than 1E+17 neutrons per square centimeter (n/cm
: 2) (E > 1.0 MeV). Hence, neutron embrittlement of Salem RPV nozzle materials will remain low during the period of extended operation, supporting that it is unnecessary to include nozzle specimens in the Reactor Vessel Surveillance Program.
Operating Experience. In LRA Section B.2.1.19, the applicant cited evaluation results of three surveillance capsules withdrawn from 1992 to 2000 to conclude that the materials met the requirements for continued safe operation and 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 (PTS) evaluation and P
-T limits using information from all surveillance data in accordance with RG 1.99, Revision
: 2. Based on the above evaluation of the Reactor Vessel Surveillance Program, the staff concludes that the AMP has met the eight acceptance criteria of GALL AMP XI.M31 and, 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. Appendix H of 10 CFR Part 50 requires licensees to submit proposed changes to their Reactor Vessel Surveillance Program withdrawal schedules to the NRC for review and approval. To ensure that this reporting requirement will carry forward through the period of extended operation, the staff has imposed a license condition to the applicant's Reactor Vessel Surveillance Program as stated earlier in the staff's evaluation.
The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its review of the applicant's Reactor Vessel Surveillance 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 supports the requirements of the AMP. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that, with the license condition, i t provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
Aging Management Review Results 3-114 Buried Piping Inspection Summary of Technical Information in the Application. LRA Section B.2.1.22 describes the existing Buried Piping Inspection Program as consistent, with an enhancement, with GALL AMP XI.M34, "Buried Piping and Tanks Inspection."  The applicant stated that the program includes buried steel piping being managed for the aging effects of general, pitting, crevice, and microbiologically
-influenced corrosion and relies on visual inspection of excavated piping, including the associated coatings and wrappings that are installed in accordance with standard industry practices as a preventive measure. The applicant also stated that visual inspections
 
will include at least one steel, ductile cast iron and gray cast iron piping and component segment both in the 10
-year period prior to the period of extended operation and again during the period of extended operation. The applicant further stated that there are no buried tanks 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 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 AMP XI.M34. As discussed in the Audit Report, the staff confirmed that these elements are consistent with the corresponding elements of GALL AMP XI.M34.
The staff also reviewed the portions of the "detection of aging effects" program element associated with an enhancement to determine whether 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.2.1.22 states an enhancement to the "detection of aging effects" program element. The applicant stated that the program is being enhanced to include at least one inspection each for carbon steel, gray cast iron, and ductile iron piping within the period of 10 years prior to the beginning of the period of extended operation. The applicant also stated that the enhancement specifies that access to each buried piping to be inspected will be conducted as part of either an opportunistic or a focused inspection. The applicant further stated that the enhancement specifies that a minimum of one additional inspection will be conducted for each material type within the first 10 years of the period of extended operation.
The staff finds the enhancement acceptable because it requires inspection of each buried material type within the scope of the program prior to and during the first 10
-year period upon entering the period of extended operation, which exceeds the recommendations of GALL AMP XI.M34. Based on its audit, the staff finds that elements one through six of the applicant's Buried Piping Inspection Program, with acceptable enhancement, are consistent with the corresponding program elements of GALL AMP XI.M34 and, therefore, acceptable. The staff notes that even though the applicant has demonstrated consistency with each of the program elements in GALL AMP XI.M34, based on recent industry operating experience, the staff requires further information related to the applicant's use of cathodic protection and coatings and the quality of backfill in the vicinity of buried pipe. The staff issued RAIs B.2.1.22 and B.2.1.22-02,  and its evaluation is documented in the operating experience program element. The applicant's response to these RAIs may impact the "preventive actions," "parameters monitored or Aging Management Review Results 3-115 inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements.
Operating Experience. LRA Section B.2.1.22 summarizes operating experience related to the Buried Piping Inspection Program. The applicant stated that in one example of plant
-specific operating experience, wrappings were determined to be missing from a portion of out of scope fuel oil piping resulting in leakage; repairs were conducted on the piping and the correct wrapping was installed. The applicant also stated that in another instance, a joint in the service water system failed due to loads from the road surface above the buried pipe; inspections of associated piping during the repair excavation revealed no age
-related degradation.
Given that there have been a number of recent industry events involving leakage from buried or underground piping, the staff needs further information to evaluate the impact that these recent industry events might have on the applicant's Buried Piping Inspection Program. By letter dated August 6, 2010, the staff issued RAI B.2.1.22 requesting that the applicant provide information regarding how the applicant will incorporate the recent industry operating experience into its AMRs and AMPs.
In its response dated September 7, 2010, the applicant stated that during planned inspections of th e Unit 1 auxiliary feedwater line it was determined that due to an error during original construction, the coating from this line was removed that resulted in the pipe wall thickness being less than nominal thickness in several areas and in some instances, only meeting operability limits after reanalysis. The applicant also stated that as part of the extent of the condition review, a portion of the Unit 2 auxiliary feedwater, station air, and control air system buried piping was excavated and the coatings were found to be in good condition with the exception of an area where a small pipe leak was found on a 1
-inch control air line buried in sand. The cause of the damage was attributed to coating damage as a result of an individual stepping on the pipe. The applicant further stated that it has risk ranked all buried piping in accordance with National Association of Corrosion Engineers (NACE) and EPRI guidelines and the NEI Industry Initiative on Buried Piping, and based on these risk rankings, inspections of the coating and external surfaces of the pipe are conducted. The applicant stated that none of the buried piping systems have cathodic protection installed. The applicant also stated that it has committed to conduct excavated visual inspections of at least 8 linear feet, when practical, of buried pipe in each material group and an additional three steel piping locations based on its recent Unit 1 auxiliary feedwater operating experience prior to entry into the period of extended operation and each 10
-year period after entry into the period of extended operation. The staff noted that based on review of documentation during the audit, subsequent reviews of the LRA, and responses to RAIs, all carbon steel piping is coated in accordance with appropriate industry standards.
Based on its review, the staff determined that it does not have sufficient information to find the applicant's response acceptable. By letter dated October 18, 2010, the staff issued follow
-up RAI B.2.1.22-02  requesting that the applicant:  (1) define what is meant by excavating 8 feet of pipe when practical, state what alternative inspection means will be used to determine the condition of the buried pipe and its coatings, or justify why inspecting less th an 8 feet is sufficient to provide a reasonable assurance of the condition of the pipe and coatings; (2) justify why it is acceptable for the buried in
-scope piping to not be cathodically protected; (3) clarify if any nonradioactive drain system buried pipe contains hazardous material and if applicable, state what percent of in
-scope buried pipe containing hazardous material will be inspected; and (4) provide details on the quality of backfill in the vicinity of in
-scope buried pipes.
 
Aging Management Review Results 3-116 The LRA states that the compressed air, demineralized water, fire protection, service water, nonradioactive drain, and auxiliary feedwater systems have buried steel piping. Pending the response to RAI B.2.1.22-02, the staff does not have sufficient information to conclude its review of the operating experience program element.
This is tracked as Open Item OI 3.0.3.2.10
-1 UFSAR Supplement. LRA Section A.2.1.22 provides the UFSAR supplement for the Buried Piping Inspection Program. The staff reviewed this UFSAR supplement description of the program and notes 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 notes that the applicant committed (Commitment No.
: 22) to enhance the Buried Piping Inspection Program prior to entering the period of extended operation. Specifically, the applicant committed to perform at least one opportunistic or focused excavation and inspection of carbon steel, ductile cast iron, gray cast iron piping, and components within 10 years prior to entering the period of extended operation and in the first 10 years of the period of extended operation.
The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's Buried Piping Inspection Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. Also, the staff reviewed the enhancement and confirmed that its implementation through Commitment No.
24 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, with the exception of Open Item OI 3.0.3.2.10
-1 , 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). 3.0.3.2.10 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 AMP XI.M35, "One
-Time Inspection of ASME Code Class 1 Small-Bore Piping."  The applicant stated that the One
-Time Inspection of ASME Code Class 1 Small-Bore Piping Program is a new program that:  (1) will be implemented prior to the period of extended
 
operation and within the last 10 years of the current operating period; and (2) manages the aging effect of cracking in stainless steel ASME Code Class 1 piping, piping elements, and piping components less than 4 inches nominal pipe size (NPS) and greater than or equal to 1 NPS (Table IWB
-2500-1, Examination Category B
-J, Item No. B9.21) in reactor coolant and treated water environments. The applicant further stated that there has not been cracking of ASME Code Class 1 small-bore piping at its site and should evidence of aging be revealed by the one-time inspection, periodic inspection will be proposed.
Aging Management Review Results 3-117 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 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 AMP XI.M35, 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.
The "parameters monitored or inspected" program element of GALL AMP XI.M35 recommends that inspections will detect cracking in ASME Code Class 1 small-bore piping. LRA Sections B.2.1.23 and A.2.1.23 state that socket welds that fall within the weld examination sample will be examined using VT
-2. The staff noted that a visual inspection of the outside diameter will not detect cracking initiated from the inside of the socket weld before leakage occurs. By letter dated June 11, 2010, the staff issued RAI B.2.1.23-1 requesting that the applicant justify how VT
-2 will detect cracking that initiates from the inside of the socket weld before leakage occurs.
In its response dated July 8, 2010, the applicant stated that as industry technology advances and methods become available to detect and characterize flaws in small
-bore socket welds, in addition to the VT
-2 visual examinations, Salem Units 1 and 2 will perform four volumetric examinations, two per unit, from a population of 36 susceptible Class 1 small-bore socket welds on Unit 1 and 34 susceptible Class 1 small
-bore socket welds on Unit 2. The applicant further stated that the locations for the volumetric socket weld examinations will be determined by selecting the socket welds where the highest likelihood of small
-bore socket weld degradation could exist.
Based on its review, the staff finds the applicant's response to RAI B.2.1.23-1 acceptable because the applicant has committed to volumetric examination of small
-bore piping socket welds which is capable of detecting cracking initiated from the inside wetted area of the weld. The staff's concern described in RAI B.2.1.23-1 is resolved.
The staff also reviewed the portions of the "scope of the 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. LRA Sectio n B.2.1.23 states an exception to the "scope of the program" program element. Specifically, the exception states that GALL AMP XI.M35 references the interim guidance contained in EPRI Report 1000701, "Interim Thermal Fatigue Management Guideline (MRP-24)," while the applicant uses a more recent revision to the MRP issue regarding thermal fatigue. The applicant also stated that since the publication of the GALL Report, the interim guidance contained in EPRI Report 1000701 has been supplemented by a more complete set of guidelines on thermal fatigue issues for lines connecting to the RCS. Furthermore, the applicant used these more recent guidelines contained in EPRI Report 1011955, "Materials Reliability Program Management of Thermal Fatigue in Normally Stagnant Non-Isolable Reactor Coolant System Branch Lines (MRP
-146)." The staff noted that MRP
-24 was an interim guidance that was issued in January 2001 and MRP-146 was issued in June 2005. The staff further noted that MRP
-146 expanded on Aging Management Review Results 3-118 MRP-24 to provide recommendations for an ongoing fatigue management program in affected lines. The staff noted that following the issuance of MRP
-24, additional testing and evaluations were undertaken by industry to better understand the thermal fatigue mechanisms that had been responsible for cracking in the non
-isolable, normally
-stagnant branch lines. The staff reviewed MRP
-146 and noted that this guideline is a replacement for MRP
-24 that is based on more recent testing and analytical modeling and provides a more comprehensive approach to assure that thermal fatigue cracking will not occur. The staff also noted that MRP
-146 includes:  (1) a larger scope of RCS
-attached piping; (2) a more detailed screening and analytical evaluation approach; (3) an evaluation of the adequacy of monitoring systems, where monitoring is used to show that valve in
-leakage is not a factor; and (4) inspection guidelines, with inspection intervals for all lines where assessment indicates the potential for thermal fatigue when compared to MRP
-24. The staff also noted that draft NUREG
-1801, Revision 2 (ADAMS Accession No.
ML101320104) dated April 2010, has proposed the use of MRP
-146. Based on its review, the staff finds this exception acceptable because the applicant is using the guidance from MRP-146 which provides more detailed and conservative guidance when compared to MRP
-24, which is recommend by the GALL Report.
Based on its audit 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 AMP XI.M35 and, therefore, 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 it has not experienced cracking of ASME Code Class 1 small-bore piping resulting from SCC or thermal and mechanical loading. The applicant provided results of inspections that demonstrate objective evidence that the new One
-Time Inspection of ASME Code Class 1 Small-Bore Piping Program is capable of both monitoring and detecting the aging effects of cracking and, therefore, there is sufficient confidence that the implementation of the program will provide additional assurance that either aging of small
-bore ASME Code Class 1 piping is not occurring or the aging is insignificant.
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 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 and, therefore, the staff finds it acceptable.
 
Aging Management Review Results 3-119 UFSAR Supplement. LRA Section A.2.1.23 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 and notes that it conforms to the recommended description for this type of program as described in SRP
-LR Table 3.1-2. The staff also notes that the applicant committed (Commitment No.
: 23) to implement the new One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program prior to entering the period of extended operation for managing aging of applicable components.
The staff determines that the information in the UFSAR supplement, as amended, is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's One
-Time Inspection of ASME Code Class 1 Small-Bore Piping Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and its justification and determines that the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. 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). 3.0.3.2.11 Lubricating Oil Analysis Summary of Technical Information in the Application. LRA Section B.2.1.27 describes the existing Lubricating Oil Analysis Program as consistent, with exceptions, with GALL AMP XI.M39, "Lubricating Oil Analysis."  The applicant stated that the program provides oil condition monitoring activities to manage loss of material and reduction of heat transfer in piping, piping components, piping elements, heat exchangers, and tanks within the scope of license renewal exposed to a lubricating oil environment. The applicant uses sampling, analysis, and condition monitoring activities to identify specific wear products, contamination, and physical properties of lubricating oil within operating machinery.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. The staff reviewed the exception to determine whether the AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. The staff confirmed that the Lubricating Oil Analysis program contains all the elements of the referenced GALL Report program and that the plant conditions are bounded by the conditions for which the GALL Report was evaluated.
In comparing program elements one through six of the applicant's program to the corresponding elements of GALL AMP XI.M39, the staff noted that each element of the applicant's program is consistent with the corresponding element of GALL AMP XI.M39.
Exception. LRA Section B.2.1.27 states an exception to the "parameters monitored or inspection" program element. The GALL Report AMP recommends the determination of flash point. The applicant stated that the determination of flash point in lubricating oil is used to indicate the presence of highly volatile or flammable materials in a relatively nonvolatile or nonflammable material, such as found with fuel contamination in lubricating oil. The applicant Aging Management Review Results 3-120 stated that flash point is not measured for inservice lubricating oil for components within the scope of the program except for new lubricating oil and for inservice EDG lubricating oil. The applicant provided justification for not performing flash point on inservice lubricating oil for components within the scope of the program by stating that the EDG inservice lubricating oil is the only potential application for the introduction of highly volatile or flammable materials (e.g., diesel fuel into the lubricating oil).
The staff reviewed this exception and the recommendations found in the GALL Report AMP.
The determination of flash point for the EDG lubricating oil and new lubricating oil was found to be acceptable since the EDG lubricating oil was found to be the only potential application for the introduction of highly volatile or flammable materials.
The staff finds this program exception acceptable and consistent with the one described in GALL AMP XI.M39 because the applicant has stated that flash point determinations are being conducted on those systems that have the potential for the introduction of highly volatile or flammable materials.
Operating Experience. LRA Section B.2.1.27 summarizes operating experience related to the Lubricating Oil Analysis 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 verified that the applicant had adequately incorporated and evaluated operating experience related to this program.
The applicant provided the following for operational experience:
  (1) In April 2004, a lubricating oil sample was taken from the Salem Unit 3 gas turbine in accordance with the predictive maintenance program. The analysis indicated moisture content and total acid number (TAN) at their Alert Levels. It was recognized that the conditions could result in bearing damage. The condition was entered into the corrective action program. Prompt actions were initiated to change the lubricating oil and filter. These actions were completed in June 2004. Data since June 2004 shows moisture content and TAN returned to their normal ranges.
  (2) In January 2004, a lubricating oil sample was taken from the lower bearing assembly of a circulating water pump motor in accordance with the predictive maintenance program.
The analysis indicated an increase in wear metal particles and a higher than normal TAN. The levels of the wear metals iron, copper, and lead did not indicate a bearing problem. The condition was entered into the corrective action program. The vibration data was reviewed and it also did not indicate a bearing problem. The elevated TAN was an indication of possible increased oxidation of the oil. The sample results were verified and discussed with system engineering. Although there was no indication of a significant problem with the lubricating oil, the recommendation was made to replace the lubricating oil at the next available window as a prudent action to protect the bearing. Prior to this replacement, additional sampling and analysis was performed in March 2004 and June 2004 to monitor the condition of the lubricating oil and to ensure that the results of the January 2004 sample were accurate.
These two additional samples indicated acceptable wear metal particle counts and TAN numbers. The sample from January 2004 was deemed to have been taken using a bad sampling technique. This apparent bad sampling technique was discussed with the Aging Management Review Results 3-121 personnel performing sampling. Replacement of the lubricating oil was canceled. Therefore, this example provides objective evidence that the Lubricating Oil Analysis Program is capable of making prudent recommendations based on sample results, performing additional sampling to monitor critical lubricating oil parameters, and to verify the validity of earlier samples, and adjusting corrective actions based on all of the analytical information.
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. 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.
The staff confirmed that the applicant addressed operating experience identified after issuance of the GALL Report. Based on its review, 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 this program has resulted in the applicant taking appropriate corrective actions. Therefore, 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.2.1.27 provides the UFSAR supplement for the Lubricating Oil Analysis Program. The staff reviewed this UFSAR supplement description of the program and notes 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 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 Lubricating Oil Analysis Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.12 ASME Section XI, SubSection IWE Summary of Technical Information in the Application. LRA Section B.2.1.28 describes the existing ASME Section XI, SubSection IWE Program as consistent, with enhancements, with GALL AMP XI.S1, "ASME Section XI, SubSection IWE."  The applicant stated that the ASME Section XI, SubSection IWE Program is a condition monitoring program that provides for inspection of the containment liner plate including its integral attachments, penetration sleeves, pressure-retaining bolting, personnel airlock and equipment hatches, moisture barrier, and other pressure-retaining components. The applicant also stated that the scope of the ASME Aging Management Review Results 3-122 Section XI, SubSection IWE Program is consistent with the scope identified in ASME Code Section XI, SubSection IWE-1000 and includes the containment moisture barrier.
The applicant included two enhancements to the ASME Section XI, SubSection IWE Program to address:  (1) inspection of the inaccessible liner plate covered by insulation and lagging and (2) visual examination of 100 percent of the moisture barrier to the extent practical within the limitation of design, geometry, and materials of construction of the components.
In a response to RAI B.2.1.28-2, in a letter dated June 30, 2010, the applicant clarified the commitment in Enhancement
: 1. The applicant stated that Enhancement 1 will include inspection of a random sample of containment liner surfaces behind the containment liner insulation prior to the period of extended operation. The sampling plan is based on guidance in EPRI TR-107514, "Age Related Degradation Inspection Method and Demonstration: in Behalf of Calvert Cliffs Nuclear Power Plant License Renewal Application."  The applicant further stated that the population size of containment liner insulation panels in each Unit is about 264 panels, so a sample size of 57 will meet the statistical confidence level of at least 95 percent tha t 95 percent of the containment liner plate behind the containment liner insulation meets the ASME Code Section XI, SubSection IWE-3500 acceptance criteria.
The second program enhancement will involve trimming the bottom edge of the stainless steel insulation lagging, if necessary, to provide access for inspection of the moisture barriers. The applicant provided details of corrective actions required for implementing Enhancement 2 in its response to RAI B.2.1.28-1, in a letter dated June 30, 2010. These corrective actions were identified as a follow
-up to the inspection performed in 2009.
The applicant also stated in the LRA that the program complies with ASME Code Section XI, SubSection IWE requirements for metallic shell and penetration liners of Class CC pressure-retaining components and their integral attachments in ASME Code Section XI, 1998 Edition including 1998 Addenda in accordance with the provisions of 10 CFR 50.55a. 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 AMP XI.S1. As discussed in the Audit Report, the staff confirmed that these elements are consistent with the corresponding elements of GALL AMP XI.S1.
The staff also reviewed the portions of the "scope of the program" program element associated with enhancements to determine whether 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.2.1.28 states an enhancement to the "scope of the program" program element. The enhancement involves inspection of a sample of the inaccessible liner plate covered by insulation and lagging prior to the period of extended operation and every 10 years thereafter. The applicant further stated that if unacceptable degradation is found, additional insulation will be removed as necessary to determine the extent of the condition in accordance with the corrective action program. In response to RAI B.2.1.28-2, the applicant stated that prior to the period of extended operation, 57 containment liner insulation panels per Unit will be selected for examination. The examinations will be conducted by either:  (1) removing the containment liner insulation panels and performing a visual inspection or Aging Management Review Results 3-123 (2) using a pulsed eddy current (PEC) remote inspection, with the containment liner insulation left in place, to detect evidence of loss of material. If evidence of loss of material is detected using PEC, the containment liner insulation panel will be subsequently removed to allow for visual and UT examination.
Enhancement 1 also has C ommitment No. 28 to remove one containment liner insulation panel selected at random, from each quadrant, in each of the three inspection periods of the 10 year inspection interval during the period of extended operation. Therefore, a total of 12 containment liner insulation panels will be selected in each unit, during each 10
-year inspection interval, to allow for examination of the containment liner behind the containment liner insulation. The applicant further stated that randomly selected containment liner insulation panels in each quadrant will not include containment liner insulation panels previously selected.
The staff reviewed this enhancement against the corresponding program element in GALL AMP XI.S1. The staff noted that inspection of the inaccessible liner plate covered by insulation is required to ensure that liner plate degradation found adjacent to the moisture barrier at the concrete floor and liner plate interface does not extend to the liner plate located behind the insulation. The selection of 57 insulation panels, out of a total of 264, for visual or PEC inspection of the liner plate will provide a statistical confidence level of 95 percent that 95 percent of the inaccessible portion of the liner plate meets the acceptance standards of ASME Code Section XI, SubSection IWE-3500. The staff also noted that if the acceptance criteria defined in IWE
-3500 is not satisfied, the sample size will be modified as recommended by EPRI TR
-107514. The staff is concerned about the use of PEC to identify degradation of inaccessible portions of the liner plate behind the insulation because it has not been used in a similar situation in the past and is not recommended by ASME Code Section XI, SubSection IWE. The applicant in a conference call, dated June 30, 2010, stated that the use of the PEC remote inspection method, with the containment liner insulation left in place, to detect evidence of loss of material is being reviewed. The applicant further stated that it will require proof that the PEC is an effective inspection method for detecting degradation of the liner before it is used for Salem IWE examination. Calibrated standards will be used and the ASME authorized nuclear inservice inspector (ANII) will witness the mock
-ups. If the PEC method is not effective, then the panels will be removed to provide access for visual inspection. The staff considers this approach for the use of PEC acceptable because the PEC method's effectiveness will be first tested and documented in mock
-ups before it is used to identify containment liner plate degradation.
Based on its review, the staff concludes that the actions proposed by the applicant for Enhancement 1 are consistent with the corresponding program element in GALL AMP XI.S1.
Enhancement 2. LRA Section B.2.1.28 states an enhancement to the "scope of the program" program element. The enhancement involves visual inspection of 100 percent of the moisture barrier located at the junction between the containment concrete floor and the containment liner. The applicant stated that the inspections will be performed in accordance with the ASME Section XI, SubSection IWE Program requirements to the extent practical within the limitation of design, geometry, and materials of construction of the components. In order to perform the moisture barrier inspections, the applicant stated that it may be necessary to trim the bottom edge of the stainless steel insulation lagging. The applicant further stated that if unacceptable degradation is found, corrective actions, including extent of the condition, will be addressed in accordance with the corrective action program. 
 
Aging Management Review Results 3-124 The staff reviewed this enhancement against the corresponding program element in GALL AMP XI.S1. The staff noted that the applicant considered it prudent to make the moisture barrier behind the liner plate insulation accessible for visual examination prior to the period of extended operation to resolve concerns involving corrosion in this area. The 100 percent visual examination of the moisture barrier, if accessible, is required during each inspection period in accordance with ASME Code Section XI, IWE Table 2500
-1. The staff further noted that additional insulation and lagging will be removed to provide access for determining the extent of the condition if degradation is found. Therefore, the staff concludes that the actions proposed by the applicant for Enhancement 2 are consistent with the corresponding program element in GALL AMP XI.S1.
Based on its audit, the staff finds that elements one through six of the applicant's ASME Section XI, SubSection IWE Program, with acceptable enhancements, are consistent with the corresponding program elements of GALL AMP XI.S1 and, therefore, acceptable.
Operating Experience. LRA Section B.2.1.28 summarizes operating experience related to the ASME Section XI, SubSection IWE Program. The applicant described four examples of operating experience for the Salem concrete containment liner and its integral attachments, penetration sleeves, pressure
-retaining bolting, personnel airlock and equipment hatches, moisture barrier, and other pressure
-retaining components. This description includes ISI findings performed in accordance with the applicant's ASME Section XI, SubSection IWE Program. The applicant stated that corrosion products were identified below the Salem Unit 1 containment liner insulation in 1995. In order to allow examination of the inaccessible liner, the applicant removed the insulation panel, performed a visual examination, and found the liner to be acceptable. In addition, the applicant performed UT inspections which revealed that all thickness readings were greater than the nominal wall thickness. The applicant further stated that the source of the corrosion product debris was not identified.
In 2005, the applicant noted that borated water was leaking down the inside of the Unit 2 containment wall. The applicant removed the liner insulation, inspected the area, and reported that no visible degradation was noted on the containment liner. To confirm visual inspection results, the applicant performed UT measurements of the containment liner and reported that all thickness readings were greater than the nominal wall thickness.
Another incident occurred in 2007, when the applicant found borated water leaking near the Unit 1 containment sump. An examination was performed but the applicant found no corrosion of the containment liner or degradation of the moisture barrier. To address the situation, the applicant began monthly monitoring activities to inspect and clean the boric acid leakage from around the containment sump enclosure until the sump leakage issue was resolved.
During the Unit 1 refueling outage in 2008, the applicant conducted a sampling inspection of the normally inaccessible containment liner and moisture barrier located behind the insulation panels. The applicant exposed these areas for inspection due to industry experience as noted in NRC IN 2004
-09 and experience at Robinson and Indian Point which have a similar insulated liner configuration. Four stainless steel panels and the associated insulation (one in each quadrant) were removed just above the floor elevation and inspected by the applicant. The applicant reported that the moisture barrier and the liner condition were found acceptable in all areas inspected and indicated that a similar inspection is planned for the Unit 2 containment liner.
Aging Management Review Results 3-125 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. 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 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 two RAIs.
In LRA Section B.2.1.28, the applicant discussed actions that were taken to address age
-related degradation issues found between 1995 and 2008 at its Salem Units 1 and 2 concrete containment structures. These issues are also discussed in the operating experience program element for the ASME Section XI, SubSection IWE Program. According to the applicant, operating experience related to NRC INs 86
-99, 88-82, and 89
-79 that describe occurrences of corrosion in steel containment shells; liner plate corrosion issues described in NRC IN 97
-10; and topics in NRC IN 2004
-09 was addressed. However, the operating experience program element for the applicant's ASME Section XI, SubSection IWE Program does not discuss operating experience related to liner plate corrosion. In addition, the applicant reported that corrosion products were identified in 1995 below the Salem Unit 1 containment liner insulation, but the source of the corrosion products was not identified. The applicant also identified an action plan for addressing liner wall corrosion that was found at Salem Unit 2 during the 2R17 refueling outage. The applicant evaluated containment liner and pressure test channel corrosion and concluded that, "The liner wall corrosion has reduced the wall thickness below the design nominal; however, the thickness is above the minimum and will not corrode below minimum wall during the next refueling outage when the region will be coated."
This evaluation included an action plan that involves conducting a root cause investigation and developing and implementing long
-term recommended repairs at the next refueling outage.
By letter dated April 15, 2010, the staff issued RAI B.2.1.28-1 requesting that the applicant:  (1) provide details of borated water leakage, if any, observed inside the Unit 2 containment during the 2009 refueling outage; (2) explain why augmented inspections of the liner plate and the moisture barrier were not performed in successive inspection intervals as required by IWE-1242 since 1995; (3) provide a summary of the liner plate degradation, including loss of liner plate thickness due to corrosion, integrity of leak chase channels, and condition of moisture barriers, as observed during the most recent inspections of Unit 1 and 2 containments; and (4) provide detailed future plans for determining corrective actions, including commitments and completion schedules for addressing steel liner plate corrosion and moisture barrier deterioration in Unit 1 and 2 containments.
In its response to RAI B.2.1.28-1, issue (1), dated May 13, 2010, the applicant stated that during the most recent Salem Unit 1 outage in the spring of 2010, no active leakage from the reactor cavity and fuel transfer canal telltales was observed. The applicant further stated that during the most recent Salem Unit 2 outage in the fall of 2009, a 60 drip per minute leak of borated water was observed at the fuel transfer canal telltale, above the door to the letdown heat exchanger room. Borated water was observed on the containment liner plate moisture barrier under the fuel transfer canal. These leaks were attributed to reactor cavity leakage. The containment liner plate and moisture barrier were examined and found to meet the IWE acceptance criteria.
 
Aging Management Review Results 3-126 The applicant responded to RAI B.2.1.28-1, issue (2) by stating that prior to April 2000, inspection of the containment was performed under the Structures Monitoring Program in accordance with 10 CFR 50.65 and 10 CFR Part 50, Appendix J. Augmented examination requirements of IWE
-1242 did not apply. The applicant further stated that Salem began implementation of containment inservice inspection (CISI) in accordance with ASME Cod e Section XI, SubSection IWE as mandated by 10 CFR Part 50.55a in April 2000. Since that time, 100 percent of accessible surface areas of the Salem Unit 2 containment liner plate were examined each inspection period of the first CISI Interval in accordance with IWE
-3500. The ASME Section XI, SubSection IWE Program and examinations identified no surface areas of the containment liner plate that require augmented examinations as specified in IWE
-1242. The 2009 containment liner plate examinations identified areas that require augmented examination. These augmented examination areas have been identified for inclusion in the Salem plan for the second CISI interval, which started in April 2010. The applicant responded to RAI B.2.1.28-1, issue (3) by stating that some local corrosion was observed in the 3/4
-inch thick knuckle plate liner area above the floor for both units, but all readings met acceptance criteria for loss of material less than 10 percent of the thickness in the analysis. The minimum thicknesses measured were 0.721 inch and 0.677 inch for Units 1 and 2, respectively.
The applicant also stated that four containment liner plate insulation panels were removed at each Unit to permit examination of the exposed 1/2
-inch thick liner plate. Corrosion of the exposed liner plate was observed, but all thickness readings met acceptance criteria for loss of material less than 10 percent of the thickness. The minimum thicknesses measured were 0.452 inch and 0.518 inch for Units 1 and 2, respectively. The applicant also stated that all of the accessible vertical leak chase channels for both units were examined. One channel for Unit 1 and six channels for Unit 2 had corrosion that extended through the channel wall (hole). The leak chase channels with the holes were cleaned out to the extent possible, and the channel and containment liner plate were visually examined with a boroscope beneath the containment floor. The channels with the holes were cut at the floor and capped to prevent moisture intrusion.
The applicant further stated that 100 percent of the moisture barrier area at the containment liner plate to concrete floor interface for both units was inspected and repaired or replaced where it did not meet the IWE acceptance criteria. For Unit 2, the applicant stated that a short segment of the moisture barrier was removed in an area with significant corrosion of the 3/4-inch thick knuckle plate above the moisture barrier, where the corrosion was suspected to occur below the moisture barrier. The moisture barrier was removed to a depth of approximately 1 inch. Some corrosion of the 3/4
-inch thick knuckle plate was noted below the surface of the moisture barrier at the floor level, but the corrosion of the 3/4
-inch thick knuckl e plate did not extend below the portion of the moisture barrier that was removed. The 3/4
-inch thick knuckle plate met the IWE acceptance criteria.
The applicant responded to RAI B.2.1.28-1, issue (4) by stating that degradation was found as a result of implementation of Enhancement 2 to its ASME Section XI, SubSection IWE Program. As a result, areas that were previously inaccessible for inspection were examined and evaluations verified the adequacy of existing conditions as described above for issue (3). According to the applicant, the following corrective actions were completed and additional corrective actions were specified:
 
Aging Management Review Results 3-127 Unit 1 - corrective actions completed during the refueling outage in the spring of 2010:  Examination of 100% of the accessible 1/2" containment liner plate and moisture barrier.
UT measurements of the 3/4" containment liner (knuckle plate) around the perimeter of the Containment.
UT measurements of the 1/2" containment liner plate where insulation panels were removed and loss of material was observed.
Coating repairs of the 3/4" containment liner (knuckle plate).
The one vertical leak chase channel with a hole was capped.
Coating repairs at areas where containment liner insulation panels were removed to allow for containment liner plate inspection and corrosion was observed. The moisture barrier was repaired or replaced.
Evaluation to confirm the identified loss of material is acceptable.
Unit 1 - additional corrective actions to be completed prior to the period of extended operation:
Perform augmented examinations of the 3/4" containment liner (knuckle plate) at 78' elevation in accordance with IWE
-2420. Perform augmented examinations of the 1/2" containment liner plate behind insulation panels, where loss of material was previously identified, in accordance with IWE
-2420. Remove 1/2" containment liner insulation panels, adjacent to accessible areas where there are indications of corrosion, to determine the extent of condition of the existing corroded areas of the containment liner plate.
 
Aging Management Review Results 3-128 Unit 2 - corrective actions completed during the refueling outage in the fall of 2009:  Examination of 100% of the accessible 1/2" containment liner plate and moisture barrier.
UT measurements of the 3/4" containment liner (knuckle plate) around the perimeter of the Containment.
UT measurements of the 1/2" containment liner plate where insulation panels were removed and loss of material was observed.
The six vertical leak chase channels with a hole were capp ed. Evaluation to confirm the identified loss of material is acceptable.
Unit 2 - additional corrective actions to be completed prior to the period of extended operation
:  Examine the accessible 3/4" containment liner (knuckle plate). If corrosion is observed to extend below the surface of the moisture barrier, excavate the moisture barrier to sound metal below the floor level and perform examinations as required by IWE.
Perform remote visual inspections, of the six capped vertical leak chase channels, below the containment floor to determine extent of condition.
Remove the concrete floor and expose the 1/4" containment liner plate (floor) for a minimum of two of the vertical leak chase channels with holes. Perform examinations of exposed 1/4" containment liner plate (floor) as required by IWE. Additional excavations will be performed, if necessary, depending upon conditions found at the first two channels.
Remove 1/2" containment liner insulation panels, adjacent to accessible areas where there are indications of corrosion, to determine the extent of condition of the existing corroded areas of the containment liner plate.
Perform augmented examinations of the 1/2" containment liner plate behind insulation panels, where loss of material was previously identified, in accordance with IWE
-2420. Examine 100% of the moisture barrier in accordance with IWE
-2310 and replace or repair the moisture barrier to meet the acceptance standard in IWE-3510. The applicant further stated that, "examinations and inspections will be performed in accordance with IWE-2000 and the acceptance standards will be in accordance with IWE
-3500."
Aging Management Review Results 3-129 The staff finds the corrective actions described above in response to RAI B.2.1.28-1 comprehensive and acceptable because loss of material due to corrosion is being managed in accordance with applicable requirements in ASME Code Section XI, SubSection IWE including enhancements. However, the staff is concerned about the applicant's timeline for completing the corrective actions.
The most recent IWE inspections of the Unit 1 and Unit 2 containment liners were performed in the spring of 2010 and fall of 2009, respectively. These inspections identified the need for augmented inspections and other corrective actions in accordance with the requirements in ASME Code Section XI, SubSection IWE. IWE-2420 requires that augmented inspections be completed during the next inspection period. The period of extended operation for Salem Units 1 and 2 will commence in August 2016 and April 2020, respectively. The staff is concerned that delays in completing the augmented inspections and corrective actions until prior to the start of the period of extended operation may affect the leak tightness of the containment liner.
During a conference call on June 30, 2010, the applicant responded to staff concerns about the timeline for completing the corrective actions by stating that the Unit 1 liner area at the floor junction has already been cleaned and painted and the moisture barrier replaced at the floor and knuckle plate area. No degradation of the Unit 1 liner below the moisture barrier was evident. The Unit 2 liner area at the floor junction will be cleaned and painted and the moisture barrier repaired at the floor and knuckle plate area during the next outage. Degradation of the liner below the moisture barrier will also be investigated during the next outage. The applicant further stated that the corrective actions for insulation removal will start during the next outage but may not be completed if there is corrosion that leads to a wider inspection area. Therefore, the removal of the insulation panels may be scheduled and completed over the next few outages if any corrosion found is limited to small areas and does not compromise the liner plate thickness margin. If sufficient margin is not assured, the inspections will be expedited in accordance with IWE but random samples may get postponed.
The staff considered the applicant's response provided in the June 30, 2010, conference call and finds that the applicant's commitment to complete the corrective actions by August 2016 and April 2020 for Units 1 and 2 too long and can affect the ability of the containment liner plate to perform its intended function during the period of extended operation. Therefore, the staff has issued follow-up RAI B.2.1.28-3 on August 3, 2010, requesting that the applicant provide a detailed schedule for performing corrective actions and augmented inspections for the Unit 1 and 2 containment liners that comply with the requirements in ASME Section XI, SubSection IWE. In its response to RAI B.2.1.28-3, dated September 1, 2010, the applicant stated that the examinations of the Salem Unit 1 and Salem Unit 2 containment liners, conducted in 2009 and 2010, comply with the requirements of the 1998 Edition of ASME Section XI, SubSection IWE and 10 CFR 50.55a. The examination results, which identified degradation, were entered into the Corrective Action Program, and evaluated or repaired to ensure containment integrity. The applicant further stated that the entire Salem Unit 1 Containment liner area at the floor junction has been examined, evaluated, cleaned, and painted, and moisture barrier replaced during the spring of 2010 refueling outage. No degradation of the liner below the moisture barrier was evident. The corrective actions requiring the containment liner insulation removal, in areas where the potential for Containment liner corrosion is suspected, will be continued during the next refueling outage. The applicant also stated that the Salem Unit 2 Containment liner area at the floor junction will be examined, evaluated, cleaned, and painted, and moisture barrier repaired during the next refueling outage, in spring of 2011. Degradation of liner below the moisture barrier will be also investigated during the next refueling outage.
 
Aging Management Review Results 3-130 The applicant in its response to RAI B.2.1.28-3 also stated that the schedule for performing corrective actions and augmented inspections for the Salem Unit 1 and Salem Unit 2 Containment liners complies with the requirements in ASME Section XI SubSection IWE and 10 CFR 50.55a. The applicant further stated that augmented inspections for both Salem Unit 1 and 2 will be completed within the next two outages, which will be by 2013. In addition, in response to RAI B.2.1.33-6 concerning minimal leakage on to the Containment liner plate from the reactor cavity and fuel transfer canal during the refueling operations, the applicant revised a commitment (Commitment 28). This commitment requires that the owner augmented inspections will be performed at the Salem Unit 1 and Unit 2 area of the Containment liner, under the fuel transfer canal and behind the Containment liner insulation, which are subjected to leaks from the reactor cavity.
These owner augmented inspections will be performed on a frequency of once per Containment Inservice Inspection Period, starting with the current Period.
These owner augmented inspections will continue, under the IWE program, as long as leakage from the reactor cavity or fuel transfer canal is observed between the Containment liner, and the Containment liner insulation, including during the PEO.
The staff finds the applicant's response to RAI B.2.1.28-3 and revision to the Commitment 28 acceptable because the applicant will perform augmented inspections of the Salem Unit and Salem Unit 2 Containment liner in accordance with the ASME Section SubSection IWE Requirements.
Article IWE
-2420 of the ASME Section XI, SubSection IWE states that, "when examination results require evaluation of flaws or areas of degradation in accordance IWE-3000, and the component is acceptable for continued service, the areas containing such flaws or areas of degradation shall be reexamined during the next inspection period listed the schedule of inspection of IWE
-2411 or IWE 2412, in accordance with Table IWE-2500-1, Examination Category EC."
In the operating experience program element of the ASME Section XI, SubSection IWE Program, the applicant discussed sampling inspections of normally inaccessible areas of the steel liner plate located behind the insulation panels around the lower 30 feet of the Unit 1 containment that were completed in 2008.
By letter dated April 15, 2010, the staff issued RAI B.2.1.28-2 requesting that the applicant:  (1) describe the sampling methodology used in the 2009 inspection to select the containment liner plate and moisture barrier inspection locations behind the insulating panels and (2) provide the sampling methodology planned for future inspections.
In its response dated May 13, 2010, the applicant stated that random sampling was not used in 2009 to select the locations for inspecting the containment liner plate and the moisture barrier behind the containment liner insulation lagging. The applicant also stated that, "Salem is committed to enhance the ASME Section XI, SubSection IWE, aging management program to require inspections of a sample of the inaccessible containment liner covered by containment liner insulation and lagging prior to the period of extended operation and every 10 years thereafter."  The following details of this commitment were provided by the applicant:
Prior to the period of extended operation (PEO)
A sampling plan will be developed based upon guidance in EPRI TR-107514, "Age Related Degradation Inspection Method and Demonstration: in Behalf of Calvert Cliffs Nuclear Power Plant License Renewal Application."
 
Aging Management Review Results 3-131  The population size of containment liner insulation panels in each Unit is approximately 264 panels. A sample size of 57 will meet the statistical requirements of a 95% confidence level that 95% of the containment liner plate behind the containment liner insulation meets the acceptance criteria of IWE
-3500. The samples will be randomly selected.
The examination will be performed by either removing the containment liner insulation panels and performing a visual inspection, or by using a pulsed eddy current (PEC) remote inspection, with the containment line r
insulation left in place, to detect evidence of loss of material. If evidence of loss of material is detected using PEC, the containment liner insulation panel will be subsequently removed to allow for visual and UT examinations.
If acceptance criteria defined in IWE
-3500 is not satisfied, the sampling plan will be modified as recommended in EPRI TR
-107514. During the period of extended operation During the PEO, a reduced sample size will be randomly selected and examined each Containment Inservice Inspection Period contingent upon satisfactory results of the sample examined prior to the PEO.
One containment liner insulation panel will be selected, at random, for removal from each quadrant, during each of the three Periods in an Inspection Interval. Therefore, a total of 12 containment liner insulation panels will be selected, in each unit, during each ten year Inspection Interval, to allow for examination of the containment liner behind the containment liner insulation.
The randomly selected containment liner insulation panels in each quadrant will not include containment liner insulation panels previously selected. The staff finds the applicant's response to RAI B.2.1.28-2 regarding the size and selection of random sample acceptable because it will ensure that loss of material due to corrosion is being managed in accordance with applicable requirements in ASME Code Section XI, SubSection IWE. The sampling methodology will provide a statistical confidence level of at least 95 percent that the results of the inspection will meet the acceptance criteria of IWE
-3500. However, the staff noted that the applicant plans to implement the random sampling plan by August 2016 and April 2020 for Unit 2 too distant.
During a conference call on June 30, 2010, the applicant responded to staff concerns about the timeline for completing the random inspections by stating that the sampling plan will be implemented before 2016 and there will not be a long wait. The commitment is just stating that Aging Management Review Results 3-132 it will be completed prior to the period of extended operation. It may not be completed in a single outage depending upon what is found. Any corrosion found during examinations is addressed under the IWE requirements. The random sampling plan is not an IWE required inspection.
The staff considered the applicant's response provided in the June 30, 2010, conference call and finds that the applicant's commitment to complete the corrective actions prior to the period of extended operation too long and that the ability of the containment liner plate to perform its intended function during the period of extended operation could be adversely affected. The most recent IWE inspections of the Unit 1 and Unit 2 containment liners were performed in the spring of 2010 and fall of 2009, respectively. These inspections identified the need for inspecting inaccessible portions of the containment liners located behind the insulation panels because corrosion was detected in some liner plate sections located behind the insulation. The period of extended operation for Salem Units 1 and 2 will commence in August 2016 and April 2020, respectively. The staff is concerned that corrosion in the inaccessible portions of the liners could remain undetected until the period of extended operation. Section 54.3 of 10 CFR requires that the effects of aging on the functionality of i n-scope structures such as the containment liner be managed to maintain the CLB during the period of extended operation. In addition, the RAI response does not clearly identify the time gap between inspections of liner plates located behind 57 randomly selected insulation panels and the subsequent inspections of liner plates located behind the 12 insulation panels. Therefore, the staff has issued follow
-up RAI B.2.1.28-4 on August 3, 2010 , requesting that the applicant provide a detailed schedule for completing the random inspections and the time gap between inspections of liner plates at 57 randomly selected insulation panels and subsequent inspections at 12 insulation panels.
In its response dated September 1, 2010, the applicant stated that liner plate examination at 57 randomly selected locations, are planned to be implemented by August 2016 for both Salem units. It has not yet been finalized whether these liner plate examinations will be scheduled during a single or multiple outages.
If the liner plate examinations are scheduled over multiple outages, the number of locations of random liner plate examinations will be approximately equal for each outage.
The current plan is to schedule the 57 random liner examinations during earlier available outages and not schedule all of the 57 random liner examinations during the last possible outage prior to August of 2016.
The current plans for Salem Unit 1 involve utilizing the following outages: Spring 2013, Fall 2014, and Spring 2016. The current plans for Salem Unit 2 involve utilizing the following outages: Fall 2012, Spring 2014, and Fall 2015. However, in the September 1, 2010 letter, the commitment 28 still states that the 57 random liner examination of the containment liner plate behind the insulation panels will be completed prior to the period of extended operation.
The staff reviewed the applicant response in RAI B.2.1.28-4 and compared with the commitment
: 28. The staff was concerned about the lack of consistency between the RAI response and commitment concerning the schedule for performing the liner plate inspection at 57 locations. The period of extended operation for Salem Units 1 and 2 will commence in August 2016 and April 2020, respectively. The applicant commitment to complete random inspection of the liner plate for Salem Units 1 and 2 by August 2016 and April 2020, respectively did not address the staff concern that corrosion in the inaccessible portions of the liners could remain undetected for a long period. Therefore, during a conference call on October, 14, 2010, the staff requested the applicant that the schedule for completing the inspections in the License Renewal Commitments be revised to make it consistent with the response in RAI B.2.1.28-4.
Aging Management Review Results 3-133 The applicant in its letter dated October 19, 2010, modified the Commitment number 28 of the License Renewal Commitment List to state, "All Inspections will be completed by August 2016 for both Salem Units. Approximately one third of the 57 inspections will be completed during each refuel outage (Salem Unit 1 involves the following refuel outages: Spring 2013, Fall 2014, and Spring 2016. Salem Unit 2 involves the following refuel outages: Fall 2012, Spring 2014, and Fall 2015). It is acceptable to perform greater than one third of the inspections in any refuel outage to accelerate the inspection schedule."  The staff finds the Commitment 28 acceptable because it is consistent with the applicant's response to the RAI B.2.1.28-4. In addition, the accelerated plan for inspection of the liner plate behind the insulation panel to be completed by August 2016 and before the period of extended operations will ensure that the effects of aging on the functionality of in
-scope structures such as the containment liner be managed to maintain the current licensing basis (CLB) during the period of extended operation in accordance with 10 CFR 54.3. Based on its audit and review of the application and the applicant's responses to RAIs B.2.1.28-1 , B.2.1.28-2, RAI B.2.1.28-3, RAI B.2.1.28-4, and revision to License renewal to Commitment 28, the staff finds that (1) 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 (2) implementation of this 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. LRA Section A.2.1.28 provides the UFSAR supplement for the ASME Section XI, SubSection IWE Program. The staff reviewed this UFSAR supplement description of the program and notes that it conforms to the recommended description for this type of program as described in SRP
-LR Table 3.5-2. The staff also notes that the applicant committed (Commitment No.
: 28) to enhance the ASME Section XI, SubSection IWE Program prior to entering the period of extended operation. Specifically, the applicant committed to:
  (1) Inspection of a sample of the inaccessible liner covered by insulation and lagging once prior to the period of extended operation and every 10 years thereafter
.  (2) Visual inspection of 100% of the moisture barrier, at the junction between the containment concrete floor and the containment liner, will be performed in accordance with ASME Section XI, SubSection IWE program requirements, to the extent practical within the limitation of design, geometry, and materials of construction of the components. The bottom edge of the stainless steel insulation lagging will be trimmed, if necessary, to perform the moisture barrier inspections. This inspection will be performed prior to the period of extended operation, and on a frequency consistent with IWE inspection requirements thereafter.
Prior to the period of extended operation, the applicant committed to examine 57 randomly selected containment liner insulation panels per unit.
The examination will be performed by either removing the containment liner insulation panels and performing a visual inspection, or by using a pulsed eddy current (PEC) remote inspection, with the containment liner insulation left in place, to detect evidence of loss of material. If evidence of loss of material is Aging Management Review Results 3-134 detected using PEC, the containment liner insulation panel will be subsequently removed to allow for visual and UT examinations.
During the period of extended operation, the applicant committed to randomly select one containment liner insulation panel for removal from each quadrant during each of the three periods in an inspection interval. By using this process, the applicant will select a total of 12 containment liner insulation panels in each Unit during each 10
-year inspection interval, to allow for examination of the containment liner behind the containment liner insulation.
The staff also notes that the applicant committed to enhance the ASME Section XI, SubSection IWE Program by performing specific corrective actions prior to entering the period of extended operation.
As a follow
-up to inspections performed during the 2009 refueling outage, the applicant committed to perform the following specific corrective actions on Unit 2 prior to entering the period of extended operation:
Examine the accessible 3/4
-inch knuckle plate. If corrosion is observed to extend below the surface of the moisture barrier, excavate the moisture barrier to sound metal below the floor level and perform examinations as required by IWE.
Perform remote visual inspections of the six capped vertical leak chase channels below the containment floor to determine extent of condition.
Remove the concrete floor and expose the 1/4
-inch containment liner plate (floor) for a minimum of two of the vertical leak chase channels with holes. Perform examination of exposed 1/4
-inch containment liner plate (floor) as required by IWE. Additional excavations will be performed, if necessary, depending upon conditions found at the first two channels.
Remove 1/2
-inch containment liner insulation panels, adjacent to accessible areas where there are indications of corrosion, to determine the extent of the condition of the existing corroded areas of the containment liner plate.
Perform augmented examinations of the areas of the 1/2
-inch containment liner plate behind insulation panels, where loss of material was previously identified, in accordance with IWE-2420. Examine 100 percent of the moisture barrier in accordance with IWE
-2310 and replace or repair the moisture barrier to meet the acceptance standard in IWE
-3510. As a follow
-up to inspections performed during the 2010 refueling outage, the applicant committed to perform the following specific corrective actions on Unit 1 prior to entry into the period of extended operation:
Perform augmented examinations of the 3/4
-inch containment liner (knuckle plate) at 78-foot elevation in accordance with IWE
-2420.
Aging Management Review Results 3-135  Perform augmented examinations of the areas of the 1/2
-inch containment liner plate behind insulation panels, where loss of material was previously identified, in accordance with IWE-2420. Remove 1/2
-inch containment liner insulation panels, adjacent to accessible areas where there are indications of corrosion, to determine the extent of the condition of the existing corroded areas of the containment liner plate.
The staff determines that the information in the UFSAR supplement, as amended is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its audit and review of the applicant's ASME Section XI, SubSection IWE 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 Commitment No.
28 prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this 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 Masonry Wall Program Summary of Technical Information in the Application. LRA Section B.2.1.32 describes the existing Masonry Wall Program as being consistent, with enhancement, with GALL AMP XI.S5, "Masonry Wall Program."  The LRA states the objective of the Masonry Wall Program is to manage aging effects so that the design basis established for each masonry wall within the scope of license renewal remains valid through the period of extended operation. The LRA further states the Masonry Wall Program is based on guidance from the NRC Bulletin 80
-11, "Masonry Wall Design," and NRC IN 87
-67, "Lessons Learned from Regional Inspections of Licensee Actions in Response to IE Bulletin 80
-11."  The LRA also states that the inspection frequency is 5 years maximum and the scope of the program will be enhanced to include structures that are not monitored under the current term but require monitoring during the period of extended operation. Periodic visual inspections address loss of material and cracking due to age-related degradation of concrete for masonry walls.
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 AMP XI.S5. 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 AMP XI.S5.
Aging Management Review Results 3-136 The staff also reviewed the portions of the "scope of the program," "parameters monitored or inspected," and "detection of aging effects" program elements associated with an enhancement to determine whether 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.2.1.32 states an enhancement to the "scope of the program" program element that includes addition of the following SCs that have been determined to be within the scope of license renewal:  (1) fire pump house, (2) masonry wall fire barriers, (3) office buildings (clean and controlled facilities buildings), (4)
SBO yard buildings, (5) service building, and (6) turbine building. The staff finds this enhancement acceptable because when implemented, the Masonry Wall Program will include all masonry walls within the scope of license renewal and will be consistent with GALL AMP XI.S5 relative to including all masonry walls identified as performing intended functions in accordance with 10 CFR 54.4. Enhancement 2. LRA Section B.2.1.32 states an enhancement to the "parameters monitored or inspected" program element that includes the addition of an examination checklist for masonry wall inspection requirements. The staff finds this enhancement acceptable because when implemented, the Masonry Wall Program will be consistent with GALL AMP XI.S5 relative to visual inspections for cracking and loss of material, and guidance in the form of a checklist on what to look for and assessment criteria have been added for examination of the masonry walls. This enhancement will help provide assurance that the effects of aging will be adequately managed in a timely manner.
Enhancement 3. LRA Section B.2.1.32 states an enhancement to the "detection of aging effects" program element that includes the specification of an inspection frequency of not greater than 5 years for the masonry walls. The staff finds this enhancement acceptable because when implemented, the Masonry Wall Program will be consistent with GALL AMP XI.S5 relative to the inspection frequency being in line with that recommended in ACI 349.39-96 to help provide assurance that the effects of aging will be adequately managed in a timely manner.
Based on its audit, the staff finds that elements one through six of the applicant's Masonry Wa ll Program, with acceptable enhancements, are consistent with the corresponding program elements of GALL AMP XI.S5 and, therefore, acceptable.
Operating Experience. LRA Section B.2.1.32 summarizes operating experience related to the Masonry Wall Program.
The LRA states that actions taken include modifications of some walls, program enhancements, follow
-up inspections to substantiate masonry wall analyses and classifications, and the development of procedures for tracking and recording changes to the walls. These actions addressed concerns identified in NRC Bulletin 80
-11 and IN 87
-67, namely unanalyzed conditions, improper assumptions, improper classification, and lack of procedural controls. The LRA further explains that operating experience is used to enhance plant programs, prevent repeat events, and prevent events that have occurred at other plants from occurring at Salem. Operating experience from external and internal sources is used. The Masonry Wall Program confirms that masonry walls are in good condition and show insignificant aging or degradation. In 2006, corrective action reports were issued to document, evaluate, and repair:  (1) a degraded masonry wall tie rod (missing nut) on the controlled facilities building wall and (2) degraded masonry blocks on a seismic radiation shielding masonry wall in the mechanical penetration room. The LRA also states that the most recent structural monitoring Aging Management Review Results 3-137 inspections conducted in August 2008 for Salem Unit 1 masonry walls indicated that no walls exhibited signs of significant degradation such as efflorescence or cracking.
The staff reviewed operating experience information in the application and during the onsite 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 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.2.1.32 provides the UFSAR supplement for the Masonry Wall Program. The staff reviewed this UFSAR supplement description and notes that it conforms to the recommended description for this type of program as described in SRP-LR Table 3.5-2. The staff also notes that the applicant committed (Commitment No.
: 32) to enhance the Masonry Wall Program prior to entering the period of extended operation. Specifically, the applicant committed to:  (1) include additional buildings and masonry walls as described in LRA Section A.2.1.32, (2) add an examination checklist for masonry wall inspection requirements, and (3) specify an inspection frequency of not greater than 5 years for masonry walls.
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 Masonry Wall Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that their implementation through Commitment No.
32 prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.14 Structures Monitoring Program Summary of Technical Information in the Application. LRA Section B.2.1.33 describes the existing Structures Monitoring Program as being consistent, with enhancement, with GALL AMP XI.S6, "Structures Monitoring Program."  The LRA explains that the objective of the applicant's Structures Monitoring Program is to manage aging effects of structures or structural components such that there is no loss of intended function. The Structures Monitoring Program was developed and implemented to meet regulatory requirements and guidance of Aging Management Review Results 3-138 10 CFR 50.65, "Maintenance Rule;" USNRC Regulatory Guide 1.160 (Rev.
2); and NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants."  The program includes masonry walls evaluated in accordance with NRC IEB 80-11, "Masonry Wall Design," and incorporates guidance in NRC IN 87
-67, "Lessons Learned from Regional Inspection of Licensee Actions in Response to IE Bulletin 80
-11."  The LRA also explains that Salem is not committed to RG 1.127, "Inspection of Water
-Control Structures Associated With Nuclear Power Plants," but water control structures (service water intake structure and shoreline protection and dike structures) will be monitored consistent with requirements of RG 1.127 which are incorporated into the applicant's Structures Monitoring Program. The program also relies on plant procedures that are based on guidance contained in EPRI TR-104213, "Bolted Joint Maintenance and Applications Guide,"
to ensure proper specification of bolting material, lubricant, and installation torque. The LRA states that structures and structural components are periodically inspected by qualified personnel having a B.S. Engineering degree and/or Professional Engineer license, and a minimum of four years working on building structures. The LRA also states that protective coatings are not relied upon to manage the effects of aging for structures included in the scope of the AMP so are not addressed.
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 AMP XI.S6. 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 AMP XI.S6, 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. While reviewing the "detection of aging effects" program element, the staff noted that the LRA states that groundwater intrusion has been observed through seismic expansion joints, concrete
 
construction joints, and expansion and shrinkage cracks in the concrete, and that underground reinforced concrete structures and structures in contact with raw water alem are subject to an aggressive environment. Groundwater and raw water chemistry results in 2008 and 2009 indicate chloride levels up to 15,000 ppm that exceeds the GALL Report threshold limit for chlorides (less than 500 ppm). The applicant stated that inspection of below
-grade structures will be done when exposed during plant excavations done for construction or maintenance activities. The LRA states that the structures monitoring program has been enhanced to require periodic sampling, testing, and analysis of groundwater chemistry for pH, chlorides, and sulfates, and assessing its impact on buried structures. The LRA states that the service water intake structure will be monitored to provide a bounding condition and indicator of the likelihood of concrete degradation for inaccessible portions of concrete structures. The LRA also states that there are several subgrade exterior walls that have evidence of past or present groundwater penetration. During the on
-site audit
, the applicant was asked if they had any plans for inspections of inaccessible reinforced concrete areas prior to the period of extended operation to confirm the absence of concrete degradation. The applicant responded that they did not and that operating experience indicates that there is no evidence of corrosion appearing on the interior surfaces of the concrete structures having inaccessible exterior surfaces. Since the applicant does not have plans for inspections of inaccessible areas, the groundwater is aggressive, there have been several incidences of groundwater penetration into the structures, and the condition of interior walls may not indicate the condition of the exterior walls, it is Aging Management Review Results 3-139 unclear to the staff that this is an adequate approach to managing aging of inaccessible concrete structures subjected to aggressive groundwater.
By letter dated April 15, 2010, the staff issued RAI B.2.1.33-3, asking the applicant to provide:  (1) locations where groundwater test samples were/are taken relative to safety related and important-to-safety embedded concrete walls and foundations and provide historical results (i.e., pH, chloride content, and sulfate content) including seasonal variation of results; and (2) plans for inspections in locations adjacent to embedded reinforced concrete structures where chloride levels exceed limits in GALL Report, or if no inspections or coring of concrete is planned to evaluate condition of structures (e.g., presence of steel corrosion or determination of chloride profiles), provide a basis to demonstrate that the current level of chlorides in the groundwater is not causing structural degradation of embedded walls or foundations.
By letter dated May 13, 2010, the applicant responded by providing the groundwater sampling locations as well as the sampling results for 2008, 2009 and 2010. The provided data demonstrated that the wells adequately represent the groundwater present on the site and that the pH and sulfates are within the GALL Report limits, while the chlorides are beyond the limit of 500 ppm. The applicant's response also explained that the chloride levels in the river can be as high as 8,300 ppm, well above the levels found in the groundwater. Based on this fact, the applicant explained that the Service Water Intake Structure splash zones, which are exposed to the river water, will serve as a limiting condition or 'leading indicator' of potential degradation of below-grade concrete.
The splash zone will be inspected on a frequency not to exceed five years, and any degradation determined to be due to aggressive chemical attack will be assessed for applicability to below
-grade structures and to determine if excavation of below-grade concrete for inspection is necessary.
The applicant stated that since 2000, five inspections have been conducted of the Unit 1 and Unit 2 Service Water Intake Structures and no indications of aggressive chemical attack have been recorded.
Also, the applicant stated that past excavations of below
-grade walls have shown the concrete to be in good condition.
The applicant further explained that the 'leading indicator' approach is adequate because the river water has higher chloride levels than the groundwater, the Service Water Intake Structures were built with the same concrete mix as other safety
-related structures, and the concrete cover over the reinforcing steel in the Service Water Intake Structures is the same as other safety-related structures.
The staff reviewed the applicant's response and finds it acceptable because it clearly explains why the Service Water Intake Structures can be used as an indicator of possible below
-grade concrete degradation.
The concrete mix design used for the intake structures was the same as the rest of the plant, the concrete cover is the same as the rest of the plant structures, and the intake structures are exposed to a more aggressive environment.
These characteristics make the Service Water Intake Structures an appropriate indicator of the condition of below
-grade concrete. In addition, the intake structures will be inspected on a frequency not to exceed five years, which aligns with the GALL Report recommendations.
The staff's concern in RAI B.2.1.33-3 is resolved.
The staff also reviewed the portions of the "scope of program," "parameters monitored or inspected," "detection of aging effects, and "acceptance criteria" program elements associated with enhancements to determine whether 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.2.1.33 states an enhancement to "scope of program " program element that includes addition of the following structures and components:  fire house pump; Aging Management Review Results 3-140 office buildings (clean and controlled facilities buildings); SBO yard buildings; service building; switchyard; turbine building, transmission towers; yard structures (foundations for fire water and demineralized water tanks, plant vent radiation monitoring enclosures, turbine crane runway extensions, and manholes); building penetrations and pipe encapsulations that perform flood barrier, pressure boundary, shelter and protection intended functions); pipe whip restraints and jet impingement/spray shields; trench covers and sump liners; masonry walls, including fire barriers; miscellaneous steel (catwalks, vents, louvers, platforms, etc.); vortex suppressor, ice barrier, marine dock bumper (service water intake structure); panels, racks, cabinets, and other enclosures; metal
-enclosed bus; component supports including electrical cable trays, electrical conduit, tubing, HVAC ducts, instrument racks, battery racks, and supports for piping and components that are not within the scope of ASME Section XI, SubSection IWF); and duct banks that contain safety
-related cables and cables credited for SBO and ATWS. The staff finds this enhancement acceptable because when implemented the Salem AMP B.2.1.33, "Structural Monitoring Program," will include all structures considered by the applicant to require monitoring during the period of extended operation and will be consistent with GALL AMP XI.S6 relative to the applicant specifying the structure/aging effect combinations that are managed by its structures monitoring program.
Enhancement 2. LRA Section B.2.1.33 states an enhancement to "parameters monitored or inspected" program element that includes:
  (1) Concrete structures will be observed for reduction in equipment anchor capacity due to local concrete degradation by visual inspections of concrete surfaces around anchors for cracking and spalling; (2) Clarify that inspections are performed for loss of material due to corrosion and pitting of additional steel components such as embedments, panels and enclosures, doors, siding, metal deck, and anchors; (3) Require visual inspection of penetration seals, structural seals, and elastomers for degradation (hardening, shrinkage, and loss of strength) that will lead to loss of sealing; (4) Require the following actions related to spent fuel pool liner:  perform periodic structural examination of the fuel handling building per ACI 349.3R to ensure structural condition is in agreement with analysis; monitor telltale leakage and inspect the leak chase system to ensure no blockage; and test water drained from the seismic gap for boron concentration; (5) Require monitoring of vibration isolators associated with component supports other than those covered by ASME Section XI, SubSection IW F;  (6) Add an examination checklist for masonry wall inspection requirements; and (7) Enhance parameters to be monitored for wooden components to include change in material properties, and loss of material due to insect damage and moisture damage
. The staff finds this enhancement acceptable because when implemented
, the Structur es Monitoring Program will be consistent with GALL AMP XI.S6 relative to parameters monitored or inspected being commensurate with industry codes, standards, and guidelines. This Aging Management Review Results 3-141 enhancement will help provide assurance that aging degradation leading to loss of intended functions will be detected and the extent of degradation determined so that the degradation can be adequately managed in a timely manner. Enhancement 3. LRA Section B.2.1.33 states an enhancement to "detection of aging effects" program element that includes:
  (1) Specify an inspection frequency of not grater than 5 years for the structures including submerged portions of the service water intake structure (2) Require individuals responsible for inspections and assessments for structures to have a B.S. degree and/or Professional Engineer license and a minimum of four years experience working on building structures.
  (3) Perform periodic sampling, testing, and analysis of groundwater chemistry for pH, chlorides, and sulfates on a frequency of 5 years. Groundwater samples in area of Unit 1 containment structures and Unit 1 auxiliary building will be tested for boron concentration.
  (4) Require supplemental inspections of the affected in scope structures within 30 days following an extreme environmental or natural phenomena (large floods, significant earthquakes, hurricanes, and tornadoes).
  (5) Perform a chemical analysis of ground or surface water in
-leakage when there is significant in
-leakage or there is reason to believe that the in
-leakage may be damaging concrete elements or reinforcing steel.
The staff found this enhancement acceptable because when implemented , the Structures Monitoring Program will be consistent with GALL AMP XI.S6 relative to inspection methods, inspection schedule, and inspector qualifications being commensurate with industry codes, standards, and guidelines, and inclusion of industry and plant
-specific operating experience. This enhancement will help provide assurance that the aging degradation will be detected and quantified before there is a loss of intended functions.
Enhancement 4. LRA Section B.2.1.33 states an enhancement to "acceptance criteria" that include additional acceptance criteria as contained in ACI 349.3R
-96. The staff found this enhancement acceptable because when implemented the Salem  AMP B.2.1.33, "Structures Monitoring Program," will be consistent with GALL AMP XI.S6 relative to ACI 349.3R
-96 being used to provide an acceptable basis for developing acceptance criteria for concrete structural elements, steel liners, joints, coatings, and waterproofing membranes. This enhancement will help provide assurance that the need for corrective actions will be identified before loss of intended functions.
Based on its onsite audit, and review of the applicant's response to the RAI, the staff finds that elements one through six of the applicant's Structures Monitoring Program, with acceptable enhancements, are consistent with the corresponding program elements of GALL AMP XI.S6 and, therefore, acceptable.
Operating Experience. LRA Section B.2.1.33 summarizes operating experience related to the Structures Monitoring Program. The applicant's technical personnel were interviewed during Aging Management Review Results 3-142 the on-site audit to confirm that plant
-specific operating experience revealed no degradation not bounded by industry experience. The staff reviewed operating experience information in the application and during the onsite 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. 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 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 LRA states that the spent fuel pools have experienced leakage of borated water, leakage of borated water has occurred during refueling outages, and in
-leakage of contaminated water was noted during the field walk down. The staff determined the need for additional clarification, which resulted in the issuance of RAIs.
In the LRA it notes that the spent fuel pool at Unit 1 has experienced leakage of borated water that has migrated through small cracks in the concrete to reach the seismic gap between the containment structure and fuel handling building.
The LRA states that in the 2002 test , identified evidence of spent fuel pool leakage through the wall of Unit 1 Auxiliary Building mechanical penetration room. Further investigations revealed that the leak chase and drainage system were blocked. The LRA further explains that as a result of this blockage, leakage accumulated in small gaps between the stainless steel liner and the concrete and eventually migrated to other locations through penetrations, construction joints, and cracks. During the audit, the staff learned that the seismic gap was confirmed to contain water with radionuclides characteristic of the spent fuel pool water and leakage into the seismic gap has continued. Leakage into the tell
-tale drains is occurring at a rate of about 100 gallons per day.
It is unclear to the staff that leakage of the borated water has not resulted in degradation of either the concrete or embedded steel reinforcement that is inaccessible for visual inspection.
By letter dated April 15, 2010, the staff issued RAI B.2.1.33-1, asking the applicant to:
  (1) provide historical data on the leakage occurrence and volume, and available information from chemical analysis performed on the leakage; (2) provide the root cause analysis that was used to identify the source of leakage through the liner that has resulted in accumulation of borated water between the liner and concrete, including information on the path of the leakage and structures that could potentially be affected by the presence of the borated water; (3) discuss plans for remedial actions or repairs to address leakage through the spent fuel pool liner, and in the absence of a commitment to fix the leakage prior to the period of extended operation, explain how the structures monitoring program, or other pl ant-specific program, will address the leakage to ensure that aging effects, especially in inaccessible areas, will be effectively managed during the period of extended operation; (4) provide background information and data to demonstrate that the concrete and embedded steel reinforcement have not been degraded by exposure to the borated water and that the liner will not be impacted, and  if experimental results will be used as part of the assessment, provide evidence that the test program is representative of the materials and conditions that exist in the region between the spent fuel pool liner and concrete; and (5) if a concrete sampling program (e.g., obtaining concrete cores in region affected) cannot be implemented, please explain why this is not feasible. By letter dated May 13, 2010, the applicant responded to the staff's request.
The applicant explained that in 1980, a small leak was discovered in the Spent Fuel Pool (SFP) telltale drains.
 
Aging Management Review Results 3-143 The leaks were repaired and the observed leakage was reduced to less than 0.2 gallons per day. The applicant further explained that in 2002 an active water leak was discovered through an exterior wall of the Unit 1 Auxiliary Building (AB).
Investigation into the source revealed that the SFP telltale drain system was blocked.
The applicant explained that this blockage resulted in SFP borated water leakage accumulating behind the SFP liner and ultimately to migration of borated water in to the seismic gap between the Fuel Handling Building (FHB) and the Auxiliary Building. The blockage was removed from the drain system and since 2003 the leakage through the drain system has been monitored.
The applicant stated that the volume of leakage is on average 100 gallons per day.
The applicant also explained that in 2010 evidence of a small active leak was detected in the Unit 2 telltale drain system.
After discovering the leak, the applicant verified that the Unit 2 telltale drains were open and the applicant will continue to monitor and trend the leakage. The applicant further explained that due to the difficulty associated with verifying the adequacy of the possibly degraded in
-place concrete, laboratory testing has been conducted to simulate the affects of borated water leakage on concrete.
From these tests the applicant has predicted a concrete degradation depth of 1.3 inches after 70 years of exposure to borated water.
Using this as a limiting value for degradation, the applicant performed a structural assessment of the FHB which showed the structure would continue to perform its intended function through the period of extended operation.
The applicant also committed (Commitment No. 5.d) to perform a shallow core sample of the SFP wall where previous inspections have shown ingress of borated water through the concrete.
The sample will be examined for degradation from borated water.
The staff reviewed the applicant's response and found that additional information was required to complete its review.
Particularly, based on the information provided, the staff did not agree that the applicant's assumed degradation after 70 years was an appropriate limiting value.
In addition, the staff was not confident the applicant's structural assessment adequately addressed the effects of borated water leakage on the reinforcing steel.
To address these concerns, the staff held a conference call with the applicant on June 30, 2010 and issued follow
-up RAI B.2.1.33-5 by letter dated August 3, 2010. An additional conference call was held with the applicant on August 30, 2010, and by letter dated September 1, 2010, the applicant responded to the follow
-up RAI. In the response the applicant explained the 1.3 inch degradation estimate in more detail. The applicant explained that the estimate was based on a least squares fit of 220 data points collected over 39 months. The applicant explained that even if boric acid reaches the reinforcing steel, it will not lead to significant degradation due to the minimal oxygen levels. The applicant also revised Commitment No. 33 to include visual inspections of the accessible SFP wall every 18 months. In the response, the applicant addressed the possibility of voids beneath the SFP liner due to degraded concrete. The applicant explained that the impact of voids has been assessed and that the liner was found to be sufficiently ductile to accommodate the load from spent fuel racks, even if the foot of a rack was positioned over an area of concrete degradation. In the response, the applicant also elaborated on the core sample. The applicant explained that the core will be at least 4 inches in diameter and approximately 2 feet deep. Reinforcing steel will be exposed for inspection when the core is taken. The applicant does not have plans in place to perform additional cores, unless unexpected adverse findings from the core or future inspections indicate additional cores are necessary. The applicant also stated that currently there are no indications of active leakage from the SFP through the SFP wall.
The staff reviewed the applicant's response and notes that the applicant has committed to visually inspect the accessible portion of the SFP walls on an 18
-month interval. The applicant Aging Management Review Results 3-144 also committed to remove a concrete core sample from the SFP wall at a location that has previously indicated water leakage. In addition, the staff notes that the applicant will continue to monitor the telltale leakage and inspect the leak chase system to ensure no blockage. Any water drained from the seismic gap will be tested for boron, chloride and sulfate concentrations, and pH. The staff also notes that an independent assessment of the SFP in 2006 concluded that the concrete appeared to be in good structural condition and there were no indications of concrete surface expansion due to reinforcement corrosion. The staff believes the applicant has appropriate programs in place to manage possible degradation of the SFP, if the leakage is contained completely within the leak chase channels. However, the staff does not understand how the applicant has concluded that the leakage is contained within the leak chase channels. Currently this issue is being tracked as Open Item 3.0.3.2.15
-1. The LRA states that leakage of borated water has occurred in Salem Units 1 and 2 reactor cavities during refueling outages, but the leaks have been contained within the Containment Building. In April 2006 visual structural examinations of the accessible portions of the containment reinforced concrete structures for Units 1 and 2 indicated that the concrete was apparently in good structural condition, however, it is unclear to the staff that leakage of the borated water has not resulted in degradation of either the concrete or embedded steel reinforcement that is inaccessible for inspection.
By letter dated April 15, 2010, the staff issued RAI B.2.1.33-2, asking the applicant to:  (1) provide historical data on the leakage occurrence and volume, and available information from chemical analysis performed on the leakage; (2) provide the root cause analysis that was used to identify the source of leakage, including information on the path of the leakage and structures that could potentially be affected by the presence of the borated water; (3) discuss plans for remedial actions or repairs to address leakage, and in the absence of a commitment to fix the leakage prior to the period of extended operation, explain how the structures monitoring program, or other plant
-specific program, will address the leakage to ensure that aging effects, especially in inaccessible areas, will be effectively managed during the period of extended operation; and (4) provide background information and data to demonstrate that concrete and embedded steel reinforcement potentially exposed to the borated water have not been degraded, and if experimental results will be used as part of the assessment, provide evidence that the test program is representative of the materials and conditions that exist.
By letter dated May 13, 2010, the applicant explained that evidence of leakage has been detected in Unit 1 since the 2005 refueling outage, and since the 2000 refueling outage in Unit 2. The leakage only occurs when the reactor cavity and fuel transfer canal are flooded.
Active leaks have only been observed sporadically with measured rates less than 100 drops per minute. The applicant further explained that the probable source of leakage is very small cracks in the reactor cavity or fuel transfer canal liner.
The majority of this leakage enters the leak collection chases; however, where the fuel transfer canal exits containment leakage migrates through the concrete and down the sides of the containment liner behind the lagging.
The applicant stated that the leakage has the potential to impact the reactor cavity and fuel transfer canal reinforced concrete structures, as well as the containment liner.
The impact of the leakage on the containment liner will be addressed by the IWE AMP.
To address the possible concrete degradation, the applicant enhanced the Structures Monitoring Program to perform periodic inspection of the telltale drains associated with the reactor cavity and fuel transfer canal.
The applicant stated that keeping the telltales free of blockage will ensure that water between the liner and concrete will only contact the concrete for short durations.
The applicant explained that remedial actions are not needed based on the Aging Management Review Results 3-145 short duration of the refueling activities and concrete exposure to borated water.
The applicant also stated that the findings associated with the FHB concrete degradation research are directly applicable to the reactor cavity leakage.
Using the assumed degradation from the FHB assessment, and adjusting the time of exposure assuming the concrete is only exposed to water during refueling outages, the applicant calculated an expected depth of degradation of 0.29 inches. The applicant stated that this degradation would not approach the reinforcing steel and the leakage has no impact on the intended function of the reactor cavity structures during the period of extended operation.
The staff reviewed the applicant's response and found that additional information was required to complete its review.
Particularly, based on the information provided, the staff did not agree that the applicant's assumptions were correct regarding concrete degradation when exposed to borated water.
In addition, the staff did not have a clear understanding of the postulated leakage path, or what corrective actions were planned to address the leakage.
To address these concerns, the staff held a conference call with the applicant on June 30, 2010 and issued follow-up RAI B.2.1.33-6 by letter dated August 3, 2010. The RAI requested the applicant to discuss any corrective actions planned to stop the borated water leakage and any plans for inspecting inaccessible portions of the containment liner located in areas of postulated leakage.
An additional conference call was held with the applicant on August 30, 2010, and by letter dated September 1, 2010, the applicant responded to the follow
-up RAI. The applicant stated that there are currently no plans to prevent the flow of borated water down the containment liner since leakage has been intermittent and when panels were removed, the liner was in good condition. The applicant further stated that the source of the leakage has not been determined and that the leakage has been small and varies between outages. The applicant committed to perform augmented inspections under the fuel transfer canal, where the containment liner is subjected to leakage. These inspections will be performed once per Containment Inservice Inspection Period, as long as leakage is observed.
The staff reviewed the applicant's response and finds it acceptable because it explains that the leakage is minimal and contained in the area below the fuel transfer canal. It also explained that the containment liner was shown to be in good condition and will continue to be inspected every inspection period when leakage is identified. These actions and commitments provide reasonable assurance that aging of the containment liner due to the fuel transfer canal leakage will be adequately managed during the period of extended operation. In regards to the possible degradation of the concrete structures due to the leakage, the staff finds the applicant's response acceptable. The applicant has programs in place to detect degradation of the SFP, which due to higher volumes and more frequent leakage, should be a leading indicator of any degradation that may occur in the refueling cavity. If any degradation is noted in the SFP, the condition will be entered in the applicant's corrective action program, and the impact on the refueling cavity will be analyzed. The leading indicator of the SFP, along with Structures Monitoring Program visual inspections on a five
-year frequency provide reasonable assurance that aging of the containment internal concrete structures will be properly managed during the period of extended operation. The staff's issues in RAI B.2.1.33-2 and follow-up RAI B.2.1.33-6 are resolved.
During the field walkdown with the applicant's technical staff on February 12, 2010, the staff noticed minor indications of degradation in several areas (e.g., cracking, efflorescence, leaching, and water). At Salem Unit 1 Auxiliary Building Elevation 64 (below ground water level) there was evidence of water in
-leakage through the wall and the area was roped off as an exclusion zone. The applicant was asked about this and informed the staff that the source of Aging Management Review Results 3-146 the contamination was from in
-leakage of groundwater and that the groundwater had picked up the contamination external to the wall.
By letter dated April 15, 2010 , the staff issued RAI B.2.1.33-4 , asking the applicant to provide information on how the in
-leakage of contaminated groundwater will be addressed under the corrective action program.
By letter dated May 13, 2010, the applicant explained that the leakage has been identified at shrinkage cracks in the below
-grade Auxiliary Building concrete wall.
An initial inspection and evaluation has been conducted and it has been concluded that the current condition does not adversely impact the structure's intended function.
The response also explained that the crack area is currently in the corrective action program to be cleaned so a detailed engineering inspection can be performed to ensure long term aging issues are identified and any other required corrective actions can be performed.
In addition, the applicant explained that the Structures Monitoring Program includes an enhancement to perform a chemical analysis of in-leakage, when the leakage is significant or there is reason to believe the leakage may be damaging concrete elements or the reinforcing steel.
The staff finds this acceptable because the applicant explained that the leakage is being tracked in the corrective action program and there are plans in place to perform a detailed engineering inspection to identify, and address, possible aging concerns which may negatively affect the structure's intended function during the period of extended operation.
In addition, as discussed above in the response RAI B.2.1.33-3, the applicant is using the condition of concrete in the Service Water Intake Structures as a 'leading indicator' of possible degradation of the inaccessible below
-grade concrete structures.
The staff's concern in RAI B.2.1.33-4 is resolved.
Based on its audit and review of the application, and review of the applicant's response to RAIs as discussed above, pending resolution of Open Item 3.0.3.2.15
-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 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. In LRA Section Appendix A, "Final Safety Analysis Report Supplement,"the applicant provided the UFSAR supplement for the Structures Monitoring Program. The staff reviewed this UFSAR supplement Section and notes that it conforms to t he recommended description for this type of program as described in SRP
-LR Table 3.5-2. The staff also notes that the applicant committed (Commitment No.
: 33) to enhance the Structures Monitoring Program prior to entering the period of extended operation. Specifically, the applicant committed to: 
  (1) Include additional structures and components as described in LRA Section A.2.1.33;  (2) Observe concrete structures for a reduction in equipment anchor capacity due to local concrete degradation.
This will be accomplished by visual inspection of concrete surfaces around anchors for cracking, and spalling
;    (3) Clarify that inspections are performed for loss of material due to corrosion and pitting of additional steel components, such as embedments, panels and enclosures, doors, siding, metal deck, and anchors
;.
Aging Management Review Results 3-147  (4) Require inspection of penetration seals, structural seals, and elastomers, for degradations that will lead to a loss of sealing by visual inspection of the seal for hardening, shrinkage and loss of strength
.    (5) Require the following actions related to the spent fuel pool liner:  (a) perform periodic structural examination of the Fuel Handling Building per ACI 349.3R to ensure structural condition is in agreement with the analysis, (b) monitor telltale leakage and inspect the leak chase system to ensure no blockage, and (c) test water drained from the seismic gap for boron concentration; (6) Require monitoring of vibration supports other than those covered by ASME XI, SubSection IWF;    (7) Add an Examination Checklist for masonry wall inspection requirements
.    (8) Enhance parameters monitored for wooden components to include: Change in Material Properties, Loss of Material due to Insect Damage and Moisture Damage.    (9) Specify an inspection frequency of not greater than 5 years for structures including submerged portions of the service water intake structure
.    (10) Require individuals responsible for inspections and assessments for structures to have a B.S. Engineering degree and/or Professional Engineer license, and a minimum of four years experience working on building structures
.    (11) Perform periodic sampling, testing, and analysis of ground water chemistry for pH, chlorides, and sulfates on a frequency of 5 years.
Groundwater samples in the areas adjacent to Unit 1 containment structure and Unit 1 auxiliary building will also be tested for boron concentration; (12) Require supplemental inspections of the affected in
-scope structures within 30 days following extreme environmental or natural phenomena (large floods, significant earthquakes, hurricanes, and tornadoes);
  (13) Perform a chemical analysis of ground or surface water when there is significant
 
in-leakage or there is reason to believe that the in
-leakage may be damaging concrete elements or reinforcing steel; and (14) Enhance implementing procedures to include additional acceptance criteria details specified in ACI 349.3R
-96. 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 onsite 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, pending resolution of the Open Item discussed above. Also, the staff reviewed the enhancements and confirmed that their implementation through Commitment No.
33 prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it was compared.
The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the Aging Management Review Results 3-148 period of extended operation, as recommended by 10 CFR 54.21(a)(3).
The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.15 RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Summary of Technical Information in the Application. LRA Section B.2.1.34 describes the existing RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program as consistent, with enhancements, with GALL AMP XI.S7, "RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants."
The applicant stated RG 1.127 is implemented through the Structures Monitoring Program (10 CFR 50.65) and is based on the guidance provided in RG 1.127 and ACI 349.3R. The applicant stated that Salem is not committed to RG 1.127; however, Salem has been implementing the guidance of RG 1.127 to the structures within the scope of license renewal. These structures include the service water intake structure and shoreline protection and dike structures (including the outer walls of the circulating water intake structure). The applicant further stated that accessible structures are monitored on a frequency of 5 years consistent with the frequency for implementing the requirements of the 10 CFR 50.65 Maintenance Rule and that its program will be enhanced to include an inspection frequency of 5 years for SCs submerged in water and annual inspections for shoreline protection structures.
The applicant stated safety and performance instrumentation such as seismic instrumentation, horizontal and vertical movement instrumentation, uplift instrumentation, and other instrumentation described in RG 1.127 are not incorporated in the design of Salem water
-control structures. Thus, inspection activities related to safety and performance instrumentation are not applicable and are not specified in the implementing procedures.
As noted below, the applicant stated that prior to the period of extended operation the program will be enhanced to provide reasonable assurance that water
-control aging effects will be adequately managed during the period of extended operation.
Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the GALL Report. The staff 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 AMP 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 AMP XI.S7. 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 whether 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.2.1.34 states an enhancement to the "parameters monitored or inspected" program element. The LRA explains that procedures will be enhanced for monitoring wooden components to include change in material properties and loss of material due to insect Aging Management Review Results 3-149 damage and moisture damage. The staff found this enhancement acceptable because when the enhancement is implemented, the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program will be consistent with the guidance in GALL AMP XI.S7 and will provide assurance that the effects of aging will be adequately managed.
Enhancement 2. LRA Section B.2.1.34 states an enhancement to the "parameters monitored or inspected" program element. The LRA explains that procedures will be enhanced for monitoring elastomers to include hardening, shrinkage, and loss of strength due to weathering and elastomer degradation. The staff found this enhancement acceptable because when the enhancement is implemented, the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program will be consistent with the guidance in GALL AMP XI.S7 and will provide assurance that the effects of aging will be adequately managed.
Enhancement 3. LRA Section B.2.1.34 states an enhancement to the "detection of aging effects" program element. The LRA explains that procedures will be enhanced to require inspections for submerged concrete structural components to be performed by dewatering a pump bay or by a diver if the pump bay is not dewatered. The staff found this enhancement acceptable because when the enhancement is implemented, the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program will be consistent with the guidance in GALL AMP XI.S7 and will provide assurance that the effects of aging will be adequately managed.
Enhancement 4. LRA Section B.2.1.34 states an enhancement to the "detection of aging effects" program element. The LRA explains that procedures will be enhanced to specify an inspection frequency of not greater than 5 years for in
-scope structures including submerged portions of the service water intake structure. The staff found this enhancement acceptable because when the enhancement is implemented, the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program will be consistent with the guidance in GALL AMP XI.S7 and will provide assurance that the effects of aging will be adequately managed. Enhancement 5. LRA Section B.2.1.34 states an enhancement to the "detection of aging effects" program element. The LRA explains that procedures will be enhanced to require supplemental inspections of the in
-scope structures within 30 days following extreme environmental or natural phenomena (e.g., large floods, significant earthquakes, hurricanes, and tornadoes). The staff found this enhancement acceptable because when the enhancement is implemented, the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program will be consistent with the guidance in GALL AMP XI.S7 and will provide assurance that the effects of aging will be adequately managed.
Based on its audit, the staff finds that elements one through six of the applicant's RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program, with acceptable enhancements, are consistent with the corresponding program elements of GALL AMP XI.S7 and, therefore, acceptable.
Operating Experience. LRA Section B.2.1.34 summarizes operating experience related to the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program. The LRA discusses degradation of the plant's service water intake structure. In 2004, Aging Management Review Results 3-150 the applicant stated a 2
-inch separation was observed between the concrete deck slab of the cofferdam and the exterior wall of the service water intake structure due to differential settlement of the cofferdam concrete deck slab and the service water intake structure foundation wall. The base plate of the support post for the security fencing located on the cofferdam slab was severely corroded due to ponding of water on the concrete deck slab. The exterior concrete masonry wall that is part of the security barrier exhibited cracking of the blocks. There was no structural degradation noted on the service water intake structure reinforced concrete exterior wall except that the concrete coating was separating from the wall. Immediate action was to provide temporary support of the security fencing, power washing of the area, and documenting the conditions. The applicant stated that the condition was evaluated by site engineering and determined not to affect the intended function of any safety-related systems or structures. This area of the facility was subject to an aggressive environment (i.e., river water), which contributed to these degradations. The applicant stated corrective action was taken to repair the degraded conditions in accordance with plant specifications and procedures. In 2002, during the performance of preventive maintenance walkdowns to support condition monitoring of the service water intake structure, the applicant stated that spalling had occurred on the exterior concrete wall near watertight doors SW
-1 and SW-5. There was exposure of the rebar as a result of the spalling and corrosion on the rebar was noted. The condition was evaluated by design engineering and repaired in accordance with station specifications. The applicant stated as a follow
-up to this condition report, a walkdown inspection of the area was performed in 2004. It was noted that the spalling condition
 
had been repaired and no indication of additional degradation in the structure was present.
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.
UFSAR Supplement. LRA Section A.2.1.34 provides the UFSAR supplement for the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program. The staff reviewed this UFSAR supplement description of the program and notes that it conforms to the recommended description for this type of program as described in SRP
-LR Table 3.5-2. The staff also notes that the applicant committed (Commitment No.
: 34) to ongoing implementation of the existing RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program for managing aging of applicable components during the period of extended operation.
The applicant also committed (Commitment No.
: 34) to enhancing the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program prior to the period of extended operation. Specifically the applicant committed to:
  (1) enhance parameters monitored for wooden components to include change in material properties and loss of material due to insect damage and moisture damage
 
Aging Management Review Results 3-151  (2) enhance parameters monitored for elastomers to include hardening, shrinkage, and loss of strength due to weathering and elastomer degradation (3) enhance the inspection requirement for submerged concrete structural components to require that inspections be performed by dewatering a pump bay or by a diver if the pump bay is not dewatered (4) specify an inspection frequency of not greater than 5 years for structures including submerged portions of the service water intake structure (5) require supplemental inspections of the in
-scope structures within 30 days following extreme environmental or natural phenomena (e.g., large floods, significant earthquakes, hurricanes, and tornadoes)
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 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 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 Commitment No.
34 prior to the period of extended operation would make the existing AMP consistent with the GALL Report AMP to which it was compared. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.3.2.16 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Summary of Technical Information in the Application. LRA Section B.2.1.40 describes the new Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program as consistent, with an exception, with GALL AMP XI.E6, "Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements."  The applicant stated that its program manages the loosening of bolted connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation. The applicant also 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. The applicant further stated that the scope of the sampling program will consider application (medium
- and low-voltage), circuit loading (high loading), and location (high temperature, high humidity, vibration, etc.) and that the technical basis for the sample selection will be documented. The applicant also stated that the one
-time test used to confirm the absence of an aging effect with respect to electrical cable connection stressors will be a specific, proven test for detecting loose connections, such as thermography or contact resistance measurement, as appropriate for the application.
 
Aging Management Review Results 3-152 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 AMP XI.E6. As discussed in the Audit Report, the staff confirmed that each element of the applicant's program is consistent with the corresponding element of GAL L
AMP XI.E6, with the exception of the "scope of the program,"  "parameters monitored or inspected," "detection of aging effects," and "monitoring and trending" program elements.
Based on its audit, the staff finds that the "preventive actions" and "acceptance criteria" program elements of the applicant's Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program are consistent with the corresponding program elements of GALL AMP XI.E6 and, therefore, acceptabl
: e. The staff also reviewed the portions of the "scope of the program," "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "corrective actions" program elements 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. LRA Section B.2.1.40 states an exception to the "scope of the program," "parameters monitored or inspected,"
"detection of aging effects," "monitoring and trending," and "corrective actions" program elements. The applicant stated that the exception for this AMP is that the Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program is consistent with the GALL Report, as modified by the September 6, 2007, proposed revision of Interim Staff Guidance (ISG) LR
-ISG-2007-02. The ISG recommends that, prior to the period of extended operation, a one
-time inspection on a representative sample basis is warranted to ensure that either aging of metallic cable connections is not occurring and/or that the existing preventive maintenance program is effective, such that a periodic inspection program is not required. The one
-time inspection verifies that loosening and/or high resistance of cable connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, or oxidation are not occurring and, therefore, periodic inspections are not required. Subsequent to the applicant's LRA, a notice of availability of the final LR
-ISG-2007-2 was published in the Federal Register on December 23, 2009 (74 FR 68287). Therefore, the staff evaluated the AMP and LRA Sections B.2.1.40 and A.2.1.40 based on the staff's aging management guidance provided by the final LR
-ISG-2007-02 and GALL AMP XI.E6.
The staff finds the exception acceptable because the identified program elements are in accordance with GALL AMP XI.E6, as modified by the final LR
-ISG-2007-02, for compliance with the requirements of 10 CFR 54.21(a)(3) to demonstrate that the effects of aging for certain electrical cable connections not otherwise subject to the requirements of 10 CFR 50.49 will be adequately managed during the period of extended operation.
Based on its audit and review of LRA Section B.2.1.40, the staff finds that elements one through six of the applicant's Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program, with acceptable exception, are consistent with the corresponding program elements of GALL AMP XI.E6 as modified by the final LR
-ISG-2007-02 and, therefore, acceptable.
 
Aging Management Review Results 3-153 Operating Experience. LRA Section B.2.1.40 summarizes operating experience related to the Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program. Although a new program, the applicant stated that plant operating experience has successfully demonstrated the identification of loose connections through the effective use of thermography. The applicant also stated that plant operating experience is in alignment with industry experience, in that electrical connections have not experienced a high degree of failures and that existing plant installation and maintenance practices are effective. The applicant further stated that operating experience provides objective evidence that thermography will detect and/or monitor loose electrical connections. The applicant concluded that thermography and the corrective action program will resolve issues prior to the loss of intended function and, therefore, there is sufficient confidence that the implementation of the Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program will effectively confirm the absence of aging degradation of metallic cable connections. Referencing the LRA operating experience examples, the applicant concluded that the effects of aging and aging mechanisms are being adequately managed. The
 
applicant stated that these examples provide objective evidence that the AMP will be effective in resolving problems prior to loss of function.
The staff reviewed the operating experience 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. 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. Further, the staff performed a search of operating experience for the period 2000 through November 2009. Databases were searched using various keyword searches and then reviewed by technical auditor staff. Databases searched include GLs, bulletins, regulatory issue summaries (RISs), licensee event reports, event notifications,  inspection findings, and inspection reports. During its review, it was not clear based on the applicant's operating experience discussion that the referenced LRA operating experience examples were representative, in that the search methodology and criteria are not discussed, such as databases searched, connection types, timeframe, or connection stressors such as application, loading, and environment. Based on the above, the staff could not conclude that the applicant's program will 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.
By letter dated June 10, 2010, the staff issued RAI B.1.2.40-1 requesting that the applicant explain the evaluation methods and search criteria used to select the representative examples in LRA B.2.1.40 and the associated basis document. The applicant responded by letter dated July 8, 2010, and stated that a significant source for operating experience is found in historical plant documentation records, including maintenance work records, condition reports and corrective action evaluations, external operating experience evaluations, and engineering evaluations of regulatory correspondence such as NRC INs and GLs. The applicant also stated that operating experience for existing programs is found in system and program assessment documentation such as system/program manager notebooks, system health reports, program health reports and performance indicators, self assessments, and third party assessments. The Aging Management Review Results 3-154 applicant further stated that no limit was specified for historical record searches although it was preferred to use more recent examples (since 2000) with the primary focus to identify operating experience where age
-related degradation was precluded, mitigated, identified during performance testing, or otherwise detected or corrected prior to loss of component intended functions. In addition, the applicant stated that operating experience that indicated an AMP or aging management activity may not be effective was also considered, including potential enhancements to improve the program or activity that demonstrated that feedback from past operating experience results in appropriate program enhancements to improve aging management effectiveness. The applicant stated that specific operating experience was selected for discussion in the LRA regarding the AMP and that these examples were peer reviewed by a license renewal project manager and the site subject matter expert and approved by the technical lead.
With the information provided by the applicant's RAI response, the staff finds the Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program acceptable because the applicant provided a more detailed description of the data searched, evaluation methods, and search criteria employed by the applicant in selecting the representative operating experience examples. The operating experience provided by the applicant and identified by the staff's independent database search is bounded by industry operating experience with no previously unknown aging effects identified by the staff. Based on the applicant's RAI response and the staff's independent operating experience reviews, the staff concludes that the applicant's program operating experience is consistent with the guidance of SRP-LR A.1.2.3.10 such that there is reasonable assurance that the operating experienc e and conclusions provided by the applicant are representative of plant operating experience and that the Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program will effectively manage the effects of aging and aging mechanisms during the period of extended operation. The staff's concern described in RAI B.2.1.40-1 is resolved. Based on its audit, review of the LRA, and the review of the applicant's response to RAI B.2.1.40-1, 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. 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.2.1.40 provides the UFSAR supplement for the Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program. The staff reviewed this UFSAR supplement description of the program and notes that it conforms to the recommended description for this type of program as described in SRP
-LR Table 3.6-2 as modified by LR
-ISG-2007-02. The staff also notes that the applicant committed (Commitment No.
: 40) to implement the new Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program prior to entering the period of extended operation for managing aging of applicable components.
The staff determines that the information in the UFSAR supplement, as amended, is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusio n. On the basis of its review of the applicant's Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program, the staff determines those program elements for which the applicant claimed consistency with the GALL Aging Management Review Results 3-155 Report and final LR
-ISG-2007-02 are consistent. In addition, the staff reviewed the exception and its justification and determines that the AMP, with exception, is adequate to manage the aging effects for which the LRA credits it. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.17 Metal Fatigue of Reactor Coolant Pressure Boundary Summary of Technical Information in the Application. LRA Section B.3.1.1 describes the existing Metal Fatigue of Reactor Coolant Pressure Boundary Program as consistent, with enhancements, with GALL AMP X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary."  LRA Section B.3.1.1 states that the program monitors and tracks the number of critical thermal and pressure transients to ensure that the cumulative usage factors (CUFs) for the reactor vessel, the pressurizer, the steam generators, Class 1 and non-Class 1 piping, and Class 1 components subject to the reactor coolant, treated borated water, and treated water environments remain less than 1.0 through the period of extended operation. The applicant further stated that the program determines the number of transients that occur and uses software program WESTEMS to compute CUFs for select locations. The applicant also stated that the program requires generation of periodic fatigue monitoring reports on an annual basis, including a listing of transient events, cycle summary event details, CUFs, a detailed fatigue analysis report, and a cycle projection report. In addition, the applicant stated that if the fatigue usage for any location increased beyond expected, based on cycle accumulation trends and projections, or if the number of cycles would approach their limit, the corrective action program would be used to evaluate the condition and determine the corrective action.
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 AMP X.M1. As discussed in the Audit Report, the staff confirmed that these elements are consistent with the corresponding elements of GALL AMP X.M1.
The staff also reviewed the portions of the "scope of the program," "preventive actions," "parameters monitored or inspected," "monitoring and trending," and "acceptance criteria" program elements associated with the enhancements to determine whether 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.3.1.1 states an enhancement to the "parameters monitored or inspected" program element. This enhancement expands the existing program to include additional transients beyond those defined in the TSs and the UFSAR and also expands the program to encompass other components identified to have fatigue as an analyzed aging effect, which require monitoring. The applicant committed to implement this enhancement prior to the Aging Management Review Results 3-156 period of extended operation, as identified in Commitment No.
47, LRA Appendix A, Section A.5. The staff reviewed this enhancement against the corresponding program element in GALL AMP X.M1. During the staff's review, it was not evident to the staff whether the stated enhancement was being made to make the "parameters monitored or inspected" program element consistent with the corresponding element in GALL AMP X.M1. It was also not clear to the staff what was being enhanced relative to the information that was already provided for the Metal Fatigue of Reactor Coolant Pressure Boundary Program and whether the enhancement will be on the basis document or the implementing procedure, or both.
By letter dated June 30, 2010, the staff issued RAI B.3.1.1-1, Request 1, requesting that the applicant confirm if the stated enhancement is being proposed to make the "parameters monitored or inspected" program element consistent with GALL AMP X.M1. The staff also asked the applicant to clarify whether the enhancement will be of the basis document or the implementing procedure for this program, or both.
In its response dated July 28, 2010, the applicant clarified that the purpose of the stated enhancement was to make the "parameters monitored or inspected" program element consistent with the corresponding program element in GALL AMP X.M1 because the GALL Report recommends the monitoring of all plant transients that cause cyclic strains, which are significant contributors to cumulative fatigue usage. The applicant clarified that the enhancement was necessary because additional transients were identified that would need to be tracked by the program, beyond those in the current program. The applicant also clarified that the enhancement will be implemented by issuing new implementing procedures and revising current program implementing procedures to include monitoring of the additional transients added by Enhancement
: 1. Based on this review, the staff finds the applicant's response to RAI B.3.1.1-1, Request 1 acceptable because:  (1) Enhancement 1 will make the program element consistent with that in the "parameters monitored or inspected" program element in GALL AMP X.M1, and (2) the applicant has appropriately reflected this enhancement in Commitment No.
47 and will implement the enhancement prior to entering the period of extended operation, as recommended in SRP
-LR Secti on 3.0. The staff's concern described in RAI B.3.1.1-1, Request 1 is resolved.
During its review, the staff identified that the transients specified in the TS Table 5.7.1-1 are required to be tracked pursuant to the requirements in TS 5.7.1. The staff also identified that the design
-basis transients are located in the UFSAR and includes transients listed in TS Table 5.7.1-1 and transients that are outside of the TS requirements. It was not evident to the staff which process would be taken to track those design-basis transients that are in the UFSAR but that are outside TS 5.7.1. By letter dated June 30, 2010, the staff issued RAI B.3.1.1-1, Request 2, requesting that the applicant clarify the process, procedure, or protocol that will be used to track the occurrences of those design
-basis transients that are listed in the UFSAR but are not within TS 5.7.1.
In its response dated July 28, 2010, the applicant clarified that the design
-basis transients are discussed in UFSAR Section 5.2.1.5 and are listed in UFSAR Tables 5.2-10 and 5.2
-10a. The applicant also clarified that the implementation of appropriate station procedures will be used to track the occurrences of those design
-basis transients in the UFSAR that are outside of Aging Management Review Results 3-157 TS 5.7.1. The applicant clarified that the existing plant procedures currently track transients listed in the TSs but that, under Enhancement 1, the procedures will be enhanced to ensure that those design
-basis transients that are outside of TS 5.7.1 will be tracked for the period of extended operation. The applicant stated that the enhanced procedures will be credited for implementation of the Metal Fatigue of Reactor Coolant Pressure Boundary Program. The applicant stated that the implementing procedures will be annotated to identify the associated license renewal program commitments.
Based on this review, the staff finds the applicant's response to RAI B.3.1.1-1, Request 2 acceptable because the applicant clarified that its plant procedures will be use to ensure that those UFSAR design-basis transients outside of TS 5.7.1 will be tracked by the applicant's Metal Fatigue of Reactor Coolant Pressure Boundary Program and the applicant is monitoring all plant transients that cause cyclic strains, which are significant contributors to cumulative fatigue usage, as recommended by the GALL Report. The staff's concern described in RAI B.3.1.1-1, Request 2 is resolved.
The staff also noted that the applicant identified that there were additional transients that would need to be added to the scope of the program and the appropriate implementing procedures. However, the applicant did not identify which transients would need to be added to the scope of the Metal Fatigue of Reactor Coolant Pressure Boundary Program. Thus, it was not evident to the staff which transients were being referred to in the Enhancement 1 or whether it is necessary to track these additional transients for possible inclusion in updated CUF analyses. It was also not evident to the staff whether the applicant would be updating the design
-basis transients in the UFSAR to include these additional transients.
By letter dated June 30, 2010, the staff issued RAI B.3.1.1-1, Request 3, requesting that the applicant identify the additional transients that were being referred to in Enhancement 1 and clarify which ASME Code Class 1 components these additional transients are related to. The staff also asked the applicant to clarify whether an update of the design basis will be performed to include these transients and if so, identify which of the sections or tables of the UFSAR will be updated. The staff also requested that the applicant clarify whether this would be covered within the applicable LRA commitment. The staff also asked the applicant to justify its basis for omitting these transients from the design basis if the design basis will not be updated to include these transients.
In its response dated July 28, 2010, the applicant clarified that the only additional transient referred to in Enhancement 1 that is related to a Class 1 component is the "Inadvertent Auxiliary Spray to Pressurizer" transient. The applicant stated that the design
-basis transient is related to the pressurizers in the RCPB and their associated surge nozzles. The applicant stated that the transient is within the scope of the current TSs or UFSAR. The applicant clarified, however, that this transient is manually counted by the current program. The applicant clarified that this transient is included in the design basis due to its inclusion in the current program and thus, no changes to the design
-basis transient discussions in the UFSAR sections are required or are being anticipated as a result of the inclusion of this transient.
Based on its review, the staff finds the applicant's response to RAI B.3.1.1-1, Request 3 acceptable because:  (1) the applicant identified that the "Inadvertent Auxiliary Spray to Pressurizer" transient is the only additional design
-basis transient that was not accounted for in the implementing procedures, (2) the applicant clarified that the transient is already accounted for in the design basis, and (3) implementation of the enhancement will correct the omission of Aging Management Review Results 3-158 this transient in the implementing procedure prior to entering the period of extended operation. The staff's concern described in RAI B.3.1.1-1, Request 3 is resolved.
During the staff's review, it was identified that the program will be enhanced to expand the "fatigue monitoring program to encompass other components identified to have fatigue as an analyzed aging effect, which require monitoring."  However, the staff noted that Enhancement 4 is similar to Enhancement 1, which affects the "corrective actions" program element. The "corrective actions" program element of GALL AMP X.M1 states, in part, that for programs that monitor a sample of high fatigue usage locations, "corrective actions include a review of additional affected reactor coolant pressure boundary locations."  The staff noted that this program element in GALL AMP X.M1 specifically discusses expansion of programs to additional RCPB components. Thus, it is not apparent to the staff whether the expansion criteria in Enhancement 1 is applicable to the "scope of the program," "monitoring and trending," or "corrective actions" program elements or whether it is redundant with the enhancement discussed in Enhancement 4.
By letter dated June 30, 2010, the staff issued RAI B.3.1.1-1, Request 4, requesting that the applicant clarify whether the expansion criterion in Enhancement 1 is applicable to the "monitoring and trending" program element or the "corrective actions" program element or whether it is redundant with Enhancement 4. The staff also asked the applicant to justify why the expansion of transients and components aspect of Enhancement 1 is not applicable to the "scope of the program" or "monitoring and trending" program elements and if the expansion of transients and components aspect does not relate to a corrective action activity.
In its response dated July 28, 2010, the applicant clarified that the expansion criterion in Enhancement 1 is for the expansion of the number of transients and components being monitored by the Metal Fatigue of Reactor Coolant Pressure Boundary Program. The applicant also stated that it does not pertain to the expansion of American National Standards Institute (ANSI) B31.1 RCPB piping locations into the scope of the program as a result of being scoped into the environmentally
-assisted fatigue analysis. As a result, the applicant clarified that the expansion criterion in Enhancement 1 was not redundant with Enhancement 4, which does pertain to the environmentally
-assisted fatigue analysis. The applicant also clarified that, although Enhancement 1 does not provide enhancements to the "scope of the program" or the "corrective actions" program elements, a supplemental review of Enhancement 1 determined that the enhancement is applicable to the "monitoring and trending" program element because: 
(1) the "monitoring and trending" program element in GALL AMP X.M1 recommends that th e program monitor a sample of high fatigue usage locations and that the sample be augmented to include, as a minimum, the locations identified in NUREG/CR
-6260 or alternative locations based on the plant's configuration; (2) the applicant determined that additional transients and a sample of high fatigue usage locations met this GALL Report recommendation; and (3) the implementation of Enhancement 1 will account for the need to add these transients and component locations to the scope of the program, as addressed in the "parameters monitored and inspected" and "monitoring and trending" program elements.
The staff also noted that by letter dated July 28, 2010, the applicant amended Enhancement 1 to be applicable to the "parameters monitored or inspected" and "monitoring and trending" program elements. Based on its review, the staff finds the applicant's response to RAI B.3.1.1-1, Request 4 acceptable because:  (1) the applicant amended Enhancement 1 to include both the "parameters monitored or inspected" and "monitoring and trending" program elements, (2) implementation of the applicant's amended enhancement will ensure the inclusion of the additional component locations and transients into the implementing procedures, and Aging Management Review Results 3-159 (3) the implementation of the program during the period of extended operation will be consistent with the "parameters monitored or inspected" and "monitoring and trending" program element recommendations in GALL AMP X.M1. The staff's concern described in RAI B.3.1.1-1, Request 4 is resolved
. Based on its review, the staff finds Enhancement 1, when implemented prior to the period of extended operation, acceptable because it is consistent with the recommendations of GALL AMP X.M1 as described above.
Enhancement 2. LRA Section B.3.1.1 states an enhancement to the "scope of the program," "preventive actions," "parameters monitored or inspected," "monitoring and trending," and "acceptance criteria" program elements. The staff noted that this enhancement expands the existing program to use a software program to automatically count transients and calculate cumulative usage on select components. The applicant committed to implement this enhancement prior to the period of extended operation, as identified in Commitment No.
47, LRA Appendix A, Section A.5. The staff noted that this software program does not use the Green's functions analysis methodology, as discussed in NRC RIS 2008
-30 and is based on methods defined in ASME Code Section III, NB-3200. The staff noted that the applicant's enhancement incorporates use of a software program to automatically count transients and calculate cumulative usage on select components as a preventive measure to mitigate fatigue cracking of metal components of the RCPB, which is an acceptable approach and is consistent with the recommendation in GALL AMP X.M1.
During the staff's review, it was not evident whether Enhancement 2 is being made to make the "scope of the program," "preventive actions," "parameters monitored or inspected," "monitoring and trending," and "acceptance criteria" program elements consistent with the corresponding program elements in GALL AMP X.M1. It was also not apparent to the staff exactly what is being enhanced and specifically whether it will involve an enhancement of the computer programming for the monitoring software, the basis document, or the implementing procedure.
It is also not evident to the staff how this enhancement will be tied to program elements and to the implementing procedure for the software package if the enhancement only pertains to an update of WESTEMS to cover the "scope of the program," "preventive actions," "parameters monitored or inspected," "monitoring and trending," and "acceptance criteria" program elements in GALL AMP X.M1.
By letter dated June 30, 2010, the staff issued RAI B.3.1.1-2 requesting that the applicant confirm that Enhancement 2 is being proposed to make the "scope of the program," "preventive actions," "parameters monitored or inspected," "monitoring and trending," and "acceptance criteria" program elements consistent with GALL AMP X.M1. The staff also asked the applicant to clarify what will be enhanced. In addition, the staff asked the applicant to justify why the associated program elements and implementing procedure would not have to be updated to account for Enhancement 2, if the implementation of the enhancement will be limited only to an anticipated update of WESTEMS. In its response dated July 28, 2010, the applicant clarified that the Enhancement 2 will make the "scope of the program," "preventive actions," "parameters monitored or inspected," "monitoring and trending," and "acceptance criteria" program elements consistent with GALL AMP X.M1 and that each of these elements has attributes which will be enhanced with expansion to the existing software program. The applicant clarified that the current Metal Fatigue of Reactor Coolant Aging Management Review Results 3-160 Pressure Boundary Program uses a fatigue monitoring software program for monitoring of the CUF values associated with the pressurizer lower head and surge nozzle. The applicant clarified that Enhancement 2 will expand the current fatigue monitoring program to apply and implement the use of the fatigue monitoring software program to monitor the CUF values for additional selected component locations, including the remainder of environmentally
-assisted fatigue locations, that correspond to those recommended in NUREG/CR
-6260 and that the enhancement is not only limited to a potential update of WESTEMS. The applicant further clarified that the enhancement for implementation of WESTEMS will include not only installation of the fatigue monitoring software program to include monitoring for additional locations and potential CUF updates of the locations, but also call for the establishment of new procedures and revision of existing procedures and for the implementation of these procedures to account for WESTEMS. The staff noted that the implementation of the WESTEMS fatigue software involves including additional locations that are not currently being monitored by the software program. The staff also noted the enhancement to apply WESTEMS for cycle counting and potentially for CUF updates of the component locations and also includes updating the implementing procedures to incorporate the applications of WESTEMS. The staff also noted that the corresponding "scope of the program," "preventive actions," "parameters monitored or inspected," "monitoring and trending," and "acceptance criteria" program elements in GALL AMP X.M1 incorporate key component location selection, cycle monitoring, CUF update, and development of appropriate acceptance criteria elements that would need to be enveloped by the software programming in order to validate WESTEMS.
Based on its review, the staff finds the applicant's response t o RAI B.3.1.1-2 and Enhancement 2 acceptable because:  (1) the applicant is applying the enhancement for the software program to the "scope of the program," "preventive actions," "parameters monitored or inspected," "monitoring and trending," and "acceptance criteria" program elements to ensure that the implementation of the software program will be consistent with the corresponding program elements in GALL AMP X.M1; (2) the enhancement includes the need to incorporate the use of the software program into the implementing procedures; and (3) the applicant has included the need for this enhancement in LRA Commitment No.
47 to implement the enhancement prior to entering the period of extended operation. During the review of this LRA, the staff has identified concerns regarding the results determined by the WESTEMS program as a part of the ASME Code Section III fatigue evaluatio
: n. Th is concern is discussed in SER Section 4.3.4.2.2 and is identified as Open Item OI 4.3.4.2-1. Pending the resolution of the issue on the use of WESTEMS, the staff's concern described in RAI B.3.1.1-02 is resolved.
Enhancement 3. LRA Section B.3.1.1 states an enhancement to the "preventive actions," "parameters monitored or inspected," "monitoring and trending," and "acceptance criteria" program elements. The staff noted that this enhancement expands on the existing program to address the effects of the reactor coolant environment on component fatigue life by assessing the impact of the reactor coolant environment on a sample of critical components for the plant, identified in NUREG/CR
-6260. The applicant committed to implement this enhancement prior to the period of extended operation, as identified in Commitment No.
47, LRA Appendix A, Section A.5. The staff reviewed this enhancement against the corresponding program elements in GALL AMP X.M1. The staff noted that the applicant's Enhancement 3 appropriately expands the existing program to address the effects of the reactor coolant environment on component fatigue life by assessing the impact of the reactor coolant environment on a sample of critical Aging Management Review Results 3-161 components for the plant identified in NUREG/CR
-6260, as required by GALL AMP X.M1. However, it was not evident to the staff whether this enhancement was being used to make the "preventive actions," "parameters monitored or inspected," and "acceptance criteria" program elements consistent with GALL AMP X.M1. Specifically, it was not evident to the staff how this enhancement related to the acceptance criterion recommendation for environmental fatigue calculations in the "acceptance criteria" program element of GALL AMP X.M1. It is also not evident to the staff how this enhancement related to the "preventive actions" and "parameters monitored or inspected" program elements in GALL AMP X.M1, which do not mention criteria for environmental calculations or assessments.
By letter dated June 30, 2010, the staff issued RAI B.3.1.1-03 requesting that the applicant confirm that the stated enhancement is being proposed to make the "preventive actions," "parameters monitored or inspected," "monitoring and trending," and "acceptance criteria" program elements of the Metal Fatigue of Reactor Coolant Pressure Boundary Program consistent with that in GALL AMP X.M1. The applicant was also requested to clarify how this enhancement relates to conforming with the recommendations of the "acceptance criteria,"
"preventive actions," and "parameters monitored or inspected" program elements in GALL AMP X.M1. In its response dated July 28, 2010, the applicant clarified that the Enhancement 3 is proposed for the purpose of making the "preventive actions," "parameters monitored or inspected," "monitoring and trending," and "acceptance criteria" program elements consistent with those in GALL AMP X.M1. In regard to the relationship of the enhancement to the "preventive actions" program element, the applicant clarified that the enhancement will ensure that the program's monitoring methods will consider the impacts of the reactor water environment on the CUF values for the components that are monitored. The staff noted that the "preventive actions" program element of GALL AMP X.M1 recommends that maintaining the fatigue usage factor below the design code limit and considering the effect of the reactor water environment, as described under the program description, will provide adequate margin against fatigue cracking of RCS components due to anticipated cyclic strains. The staff noted that the applicant's application of Enhancement 3 to the "preventive actions" program element is being proposed to ensure that the program's monitoring of the CUFs for RCPB components will take into account the environmental effects of the reactor coolant environment on the CUF values to maintain it below the design limit of 1.0. Based on this review, the staff finds that the preventive actions, when subject to Enhancement 3, will be acceptable for implementation because:  (1) the application of the enhancement will ensure that the monitoring of the CUF values will appropriately account for the impact of the reactor coolant environment on the CUF values for the components, (2) application of the enhancement will ensure that the implementation of the "preventive actions" program element will be consistent with the corresponding "preventive actions" program element in GALL AMP X.M1, and (3) the applicant has included this enhancement as LRA Commitment No.
47 and has committed to implement this commitment prior to entering the period of extended operation.
In regard to the relationship of the enhancement to the "parameters monitored or inspected" and "monitoring and trending" program elements, the applicant clarified that the enhancement will ensure that the program's CUF monitoring methods will consider and apply the environmental fatigue life correction factor (F en) adjustments to the CUF values for a sample of RCPB components that are identified as critical environmental fatigue locations. The applicant clarified that this is in conformance with the recommendations for identifying environmentally
-assisted Aging Management Review Results 3-162 fatigue analysis component locations, as given in NUREG/CR
-6260. The staff noted that the "parameters monitored or inspected" program element of GALL AMP X.M1 recommends, in part, that the program should monitor all plant transients that cause cyclic strains and which are significant contributors to the fatigue usage factor and that the plant transients that cause significant fatigue usage for each critical RCPB component be monitored. The staff also noted that the "monitoring and trending" program element of GALL AMP X.M1 recommends that the program should monitor a sample of high fatigue usage locations and that the sample is to include the locations identified in NUREG/CR
-6260, as a minimum, or propose alternatives based on a plant's specific configuration.
Based on its review, the staff finds that the CUF monitoring methods, when subject to Enhancement 3, will be acceptable for implementation because:  (1) the applicant identified the critical RCPB locations for environmentally-assisted fatigue analyses and has applied the F en factors, (2) the enhancement will ensure the application of the program's cycle monitoring and CUF monitoring methods to the CUF values for those RCPB components that have been identified as the critical environmentally
-assisted fatigue locations, (3) this is consistent with the "parameters monitored or inspected" and "monitoring and trending" program elements of GALL AMP X.M1, and (4) the applicant has incorporated this enhancement in LRA Commitment No. 47 and has committed to implement this commitment prior to entering the period of extended operation.
In regard to the relationship of the enhancement to the "acceptance criteria" program element, the applicant clarified that the enhancement was being proposed to ensure conformance with the "acceptance criteria" program element in GALL AMP X.M1. The applicant clarified that this was being proposed to ensure that, for the critical environmentally
-assisted fatigue RCPB locations, the monitoring of the CUF values for the components would be performed against the design code CUF limits, as adjusted using the design life adjustment factors developed for assessing the impact of reactor coolant environment on the fatigue life of the components. The staff noted that the "acceptance criteria" program element of GALL AMP X.M1 recommends that the program's acceptance criteria should maintain the fatigue usage below the design code limit considering environmental fatigue effects as described under the program description. The staff noted that the applicant's acceptance criteria, which will be modified by Enhancement 3, would ensure that the monitoring of the CUF values for the critical environmentally
-assisted fatigue analysis locations would be performed against F en-adjusted CUF limits in the RCPB.
Based on its review, the staff finds that the acceptance criteria, when subject to Enhancement 3, will be acceptable for implementation because:  (1) the application of the enhancement will ensure that the acceptance criteria on CUF monitoring of the critical environmentally
-assisted fatigue locations in the RPCB will be performed against appropriate F en-adjusted CUF limits, (2) application of the enhancement will ensure that the implementation of the "acceptance criteria" program element is consistent with GALL AMP X.M1; (3) the applicant has incorporated this enhancement in LRA Commitment No.
47 and has committed to implement this commitment prior to entering the period of extended operation.
Based on its review, the staff finds the applicant's response to RAI B.3.1.1-3 and Enhancement 3 acceptable because:  (1) the applicant described in detail how its Enhancement 3 is consistent with the recommendations of the GALL Report; and (2) the staff confirmed that when Enhancement 3 is implemented prior to the period of extended operation, the applicant's program will be consistent with the recommendations of GALL AMP X.M1 as described above. The staff's concern described in RAI B.3.1.1-03 is resolved.
 
Aging Management Review Results 3-163 Enhancement 4. LRA Section B.3.1.1 states an enhancement to the "corrective actions" program element. The staff noted that this enhancement expands on the existing program element to address the expanded review of RCPB locations if the usage factor for one of the environmental fatigue sample locations approaches its design limit.
During the staff's review, it was not evident whether the stated enhancement is being made to make the "corrective actions" program element consistent with the corresponding program element in GALL AMP X.M1. It was also not apparent to the staff what is being enhanced, specifically whether the enhancement will involve the basis document or the implementing procedure. By letter dated June 30, 2010, the staff issued RAI B.3.1.1-4 requesting that the applicant confirm that the stated enhancement is being proposed to make the "corrective actions" program element consistent with that in GALL AMP X.M1. The applicant was also requested to clarify what will be enhanced.
In its response dated July 28, 2010, the applicant clarified that Enhancement 4 is being proposed to make the "corrective actions" program element consistent with that in GALL AMP X.M1. The applicant also clarified that the enhancement will ensure that new revisions to existing implementing procedures will be issued to include the review of additional RCPB locations, if the usage factor for one of the environmental fatigue sample locations approaches its design limit.
The staff noted that the "corrective actions" program element of GALL AMP X.M1 states:
The program provides for corrective actions to prevent the usage factor from exceeding the design code limit during the period of extended operation.
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 extended period of operation. For programs that monitor a sample of high fatigue usage locations, corrective actions include a review of additional affected reactor coolant pressure boundary locations. As discussed in the Appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions.
The staff noted that the applicant conservatively considers the environmentally
-assisted fatigue analysis locations in the RCPB to be high usage factor locations and Enhancement 4 ensures that the CUF monitoring would be applied to additional component locations if the monitored CUF value for an environmentally
-assisted fatigue analysis location was to reach the design limit. The staff noted that the implementation of Enhancement 4 will make the "corrective actions" program element consistent with the recommendation in GALL AMP X.M1 to include a review of additional RCPB component locations if an action limit on CUF monitoring is reached.
Based on this review, the staff finds the applicant's response to RAI B.3.1.1-4 and Enhancement 4 acceptable because:  (1) Enhancement 4 ensures that sample expansion of the program's CUF monitoring activities will be applied to other locations if the monitored CUF for a critical environmentally
-assisted fatigue analysis component was to reach its design limit, (2) Enhancement 4 is consistent with the recommendations in the corresponding "corrective actions" program element in GALL AMP X.M1, and (3) the applicant has included this enhancement as LRA Commitment No.
47 and has committed to implement this commitment prior to entering the period of extended operation. The staff has noted a concern as to whether Aging Management Review Results 3-164 the applicant verified that the locations per NURE/CR
-6260 are bounding as compared to other plant-specific locations (e.g. locations with a higher CUF value). This is discussed in SER Section 4.3.7.2 and is identified as Open Item 4.3.4.2
-1. Pending the resolution of the issue on the selection of the plant specific loctions, the staff's concern described in RAI B.3.1.1-04 is resolved. Operating Experience. LRA Section B.3.1.1 summarizes operating experience related to the Metal Fatigue of Reactor Coolant Pressure Boundary Program. The applicant stated the Metal Fatigue of Reactor Coolant Pressure Boundary Program has remained responsive to industry and plant-specific emerging issues and concerns. To support this statement, the applicant listed examples where it addresses NRC Bulletin 88
-11 and 88-08. The applicant addressed concerns raised in NRC Bulletin 88
-11 on pressurizer surge line thermal stratification by analyzing and demonstrating the acceptability of the CUF and by including the thermal stratification into the fatigue evaluation for the period of extended operation. Also, the applicant addressed concerns raised in NRC Bulletin 88
-08 on thermal stresses in piping connected to the RCS by performing evaluations to ensure that the safety injection lines, normal and alternate charging lines, and the auxiliary spray lines would not experience failure. Based on this evaluation, the applicant implemented a leakage monitoring program for the safety injection lines. In addition, the applicant demonstrated that monitored transient cycles have not exceeded the imposed 40
-year design limits and have been within their respective administrative 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 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 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 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 and, therefore, the staff finds it acceptable.
UFSAR Supplement. LRA Section A.3.1.1 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 notes that it conforms to the recommended description for this type of program as described in SRP
-LR Table 4.3-2. The staff also notes that the applicant committed (Commitment No.
: 47) to enhance the Metal Fatigue of Reactor Coolant Pressure Boundary Program prior to entering the period of extended operation. Specifically, the applicant committed to:  (1) include additional transients beyond those defined in the TSs and the UFSAR and expanding the fatigue monitoring program to encompass other components identified to have fatigue as an analyzed aging effect, which require monitoring; (2) use a software program to automatically count transients and calculate cumulative usage on select components; (3) address the effects of the reactor coolant environment on component fatigue life by assessing the impact of the reactor coolant environment on a sample of critical components for the plant identified in NUREG/CR
-6260; and (4) require a review of additional Aging Management Review Results 3-165 RCPB locations if the usage factor for one of the environmental fatigue sample locations approaches its CUF acceptance criterion limit. The staff verified that these commitment provisions specifically involve the four enhancements that the applicant proposed in LRA Section B.3.1.1, as amended, and by letter dated July 28, 2010. 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 Metal Fatigue of Reactor Coolant Pressure Boundary 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 Commitment No. 47 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). Pending the resolution of the staff's concern in the use of the WESTEMS software and their concern as to whether the applicant verified that the locations per NURE/CR-6260 are bounding as compared to other plant
-specific locations (e.g. locations with a higher CUF value). This is discussed in SER Section 4.3.7.2 and is identified as Open Item 4.3.4.2-1 3.0.3.3  AMPs That Are Not Consistent with or Not Addressed in the GALL Report In LRA Appendix B, the applicant identified the following AMPs as plant
-specific:  High Voltage Insulator s  Periodic Inspection Aboveground Non
-Steel Tanks Buried Non
-Steel Piping Inspection Boral Monitoring Program Nickel Alloy Aging Management For the AMPs not consistent with or not addressed by the GALL Report, the staff performed a complete review of the plant
-specific AMP to determine whether it was adequate to monitor or manage aging. The staff's review of these plant
-specific AMPs is documented in the following sections of this SER.
3.0.3.3.1  High Voltage Insulators Summary of Technical Information in the Application. LRA Section B.2.2.1 describes the new High Voltage Insulators Program as plant
-specific. The applicant stated that the High Voltage Insulators Program is a new condition monitoring program that manages the degradation of insulator quality at Salem due to the presence of salt deposits or surface contamination. The scope of the program includes high voltage insulators in the 500
-kV switchyard and portions of Aging Management Review Results 3-166 the 13-kV buses. The applicant also stated that the High Voltage Insulators Program includes visual inspections to detect unacceptable indications of insulator surface contamination. The visual inspections will be performed on a twice per year frequency, will be effective in detecting the applicable aging effects, and the frequency of monitoring is adequate to prevent significant degradation. The applicant also stated that this program will be implemented prior to the period of extended operation so that the intended functions of components within the scope of license renewal will be maintained during the period of extended operation.
Staff Evaluation
. 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.2.2.1 states that the High Voltage Insulators Program is a new program that manages the aging effect of degradation of insulator quality. The scope of the program includes insulators in the 500
-kV switchyard ring bus and portions of the 13.8
-kV buses. The high voltage insulators are those credited for supplying power to in
-scope components for recovery of offsite power following an SBO.
The staff reviewed the applicant's "scope of the program" program element against the criteria in SRP-LR Section A.1.2.3.1, which states that the scope of the program should include the specific SCs of which the program manages aging. The staff determined that the specific commodity groups for which the program manages aging effects are identified (insulators in the 500-kV switchyard ring bus and portions of the 13.8
-kV buses for recovery of offsite power following an SBO), 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 and, therefore, the staff finds it acceptable.
Preventive Actions. LRA Section B.2.2.1 states that the High Voltage Insulators Program is not a preventive or mitigative program. The High Voltage Insulators Program is a condition monitoring program that relies upon visual inspections of insulator surfaces in order to manage the degradation of insulator quality due to the presence of salt deposits or surface contamination.
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 condition monitoring programs do not rely on preventive actions and thus, preventive actions need not be provided. The staff notes that this is a condition monitoring program and that there is no need for preventive actions, consistent with SRP-LR Section A.1.2.3.2.
The staff confirmed that the "preventive actions" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.2 and, therefore, the staff finds it acceptable.
Parameters Monitored or Inspected. LRA Section B.2.2.1 states that walkdowns are periodically conducted to visually inspect material conditions in the switchyards. Inspections of high voltage insulators will be performed visually to determine a threshold for implementing corrective actions. These inspections will detect the presence and extent of any aging degradation due to the presence of salt deposits. The applicant also stated that porcelain Aging Management Review Results 3-167 insulators typically have a shiny surface; if the surface is dull, then contamination is present. Typically heavy contamination will be apparent by the buildup at the base area of a vertical insulator. Similarly, for insulators in the dead
-end horizontal configuration, significant drip marks are an indication that the location should be monitored. The applicant further stated that the most important area that signifies heavy contamination is when contamination is observed on the inside ridges of the underside of the bells. Evidence of salt deposits or surface contamination will be monitored and inspected to ensure high voltage insulator intended function during the period of extended operation.
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 SC intended function(s). The parameters monitored or inspected should detect the presence and extent of aging effects.
The staff noted that surface contamination is the potential aging effect of high
-voltage insulators and a buildup of contamination could enable the conductor voltage to track along the surface and can lead to insulator flashover. The staff determined that visual inspection is acceptable for detecting and managing the aging effects of salt deposits or surface contamination associated with high-voltage insulators and will ensure the component intended function during the perio d 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 and, therefore, the staff finds it acceptable.
Detection of Aging Effects. LRA Section B.2.2.1 states that system walkdowns in the switchyards are conducted periodically and include a visual inspection of high
-voltage insulator surface conditions in accordance with system engineering walkdown procedures. These walkdowns will continue into the period of extended operation and will detect any aging degradation due to the presence of salt deposits or surface contamination. These inspections will be performed visually to determine a threshold for implementing corrective actions.
The applicant stated that high
-voltage insulators within the scope of this program are to be visually inspected at least twice per year. This is an adequate period to detect aging effects before a loss of component intended function since experience has shown that aging degradation is a slow process. The applicant also stated that a twice per year inspection interval will provide multiple data points during a 20
-year period, which can be used to characterize the degradation rate. The buildup of surface contamination is typically a slow, gradual process that is even slower for rural areas with generally less suspended particles and contaminant concentrations in the air than urban areas. Salem is located in a rural area, not near heavy industry that would provide a source for contaminants. The applicant further stated that there has only been one event associated with insulator contamination, which was not age-related or time
-dependent. Therefore, operating history and plant location support a twice per year inspection frequency, which in turn provides reasonable assurance that the aging effect of degraded insulator quality will be detected prior to failure and loss of intended function.
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 SCs intended function(s) will be adequately maintained for license renewal under all CLB design conditions.
This includes aspects such as method or technique (e.g., visual, volumetric, surface inspection), frequency, and timing of Aging Management Review Results 3-168 inspection to ensure timely detection of aging effects. In addition, it states that the method or technique and frequency may be linked to plant
-specific or industry
-wide operating experience.
The staff noted that the buildup of surface contamination is a slow, gradual process and Salem is located in a rural area, not near heavy industry that would provide a source of contamination. There has only been one event associated with insulator contamination. The plant
-specific operating experience supports a twice per year inspection frequency. The staff determined that visual inspection is an acceptable technique for inspecting surface contamination of insulators and a twice per year inspection frequency is adequate to ensure timely detection of aging effects. The staff confirmed that the "detection of aging effects" program element satisfies the criterion defined in SRP
-LR Section A.1.2.3.4 and, therefore, the staff finds it acceptable.
Monitoring and Trending. LRA Section B.2.2.1 states that monitoring activities will be prescribed by procedures that contain consistent qualitative criteria for insulator surface contamination levels (e.g., slight, moderate, and heavy) and results will be documented providing a predictable extent of degradation. Visual techniques and a twice per year frequency are appropriate for monitoring high
-voltage insulators and have been employed with success by transmission and distribution organizations. The applicant also stated that qualitative criteria for insulator surface contamination levels (e.g., slight, moderate, and heavy) will allow a predictable extent and rate of surface contamination degradation. The results will be trended, from inspection to inspection, providing a basis for timely corrective actions such as insulator cleaning/washing, prior to a loss of insulator 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 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. This program element describes how the data collected are evaluated and may also include trending for a forward look. The parameter or indicator trended should be described.
The staff determined that trending for insulator surface contamination levels (e.g., slight, moderate, and heavy) will be documented and will provide a predictable extent of degradation.
The result will be trended from inspection to inspection and will provide a basis for timely corrective actions prior to a loss of intended functions. The staff confirmed that the "monitoring and trending" program element satisfies the criterion defined in SRP
-LR Section A.1.2.3.5 and, therefore, the staff finds it acceptable.
Acceptance Criteria. LRA Section B.2.2.1 states visual inspection of high-voltage insulators will be prescribed by procedures that contain consistent qualitative criteria for insulator surface contamination levels (e.g., slight, moderate, and heavy) and the results will be documented providing a predictable extent of degradation. Inspection findings are to be within the acceptance criteria of these procedures, to ensure that high
-voltage insulator intended function is maintained under all CLB design conditions during the period of extended operation.
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 Aging Management Review Results 3-169 be evaluated, should ensure that the SC intended function(s) are maintained under all CLB design conditions during the period of extended operation.
The staff determined that the applicant described acceptance criteria for insulator surface contamination levels (e.g., slight, moderate, and heavy) in the plant procedures. Inspection findings are to be within the acceptance criteria of these procedures to ensure that high
-voltage insulator intended function is maintained 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 and, therefore, the staff finds it acceptable.
Operating Experience. LRA Section B.2.2.1 summarizes operating experience related to the high-voltage insulators. The applicant stated that industry operating experience illustrates the potential for loss of insulator quality due to salt deposits and surface contamination on switchyard insulators. The applicant also stated that demonstrating the new High Voltage Insulators Program will be effective is achieved through objective evidence that shows the aging effect of degradation of insulation quality caused by the presence of salt deposits and surface contamination is being adequately managed. The applicant further stated that the following examples of operating experience provide objective evidence that the new High Voltage Insulators Program will be effective in assuring that the intended function will be maintained consistent with the CLB for the period of extended operation:
  (1) In March 1993, Crystal River Unit 3 experienced a loss of the 230
-kV switchyard (normal offsite power to safety
-related buses) when a light rain caused arcing across salt
-la den 230-kV insulators and opened switchyard breakers. In March 1993, the Brunswick Unit 2 switchyard experienced a flashover of some high
-voltage insulators attributed to a winter storm. Since 1982, Pilgrim experienced several losses of offsite power when ocean storms deposited salt on the 345
-kV switchyards, causing the insulator to arc to ground. The applicant further stated that in response to this industry experience, existing 6
-month inspections of Salem 13
-kV insulators were expanded to include the 500-kV insulators for salt contamination. The switchyard was inspected using thermography and corona detection equipment in the winter and summer of 2002, and no significant contamination buildup was found. The response and actions associated with this industry experience were revisited in 2003 following the effects of Hurricane Isabel. Switchyard insulator inspections were instituted along with contingency planning for an insulator cleaning strategy. The applicant further stated that steps for initiating inspection of switchyard insulator surfaces were added to severe weather abnormal operating procedures upon forecast of severe weather. This example provides objective evidence that industry operating experience will be applied toward this new program, and corrective actions will be taken when the quality of insulator surfaces is threatened by storms and contamination.
  (2) One plant-specific event occurred at Salem on September 18-19, 2003, when Hurricane Isabel passed a considerable distance to the south and west of the site. Strong winds with gusts in excess of 60 miles per hour (mph) caused switchyard insulators to become coated with salt. The rain had stopped prior to the strongest winds, leaving the salt spray to dry on switchyard insulators. Both Salem units operated throughout the storm. The combination of salt on the insulator surface and atmospheric moisture subsequently caused a flashover. The applicant also stated that circuit breakers opened as designed to isolate the fault on the Salem end of the line, without effect on Salem plant equipment. Another insulator flashover occurred shortly thereafter with no effect on plant operation. In response to the switchyard faults, both Salem units were manually taken offline on Aging Management Review Results 3-170 September 20th. The high
-voltage insulators were subsequently cleaned/washed prior to returning the units to operation. The applicant further stated that this event demonstrates that corrective actions are taken when high
-voltage insulator degradation is found and because this is the only high
-voltage insulator
-related event of record, flashover due to salt contamination of insulators at Salem is considered rare.
  (3) Visual inspection of Salem switchyard high
-voltage insulators is performed twice per year for evidence of salt and contamination. These inspections have been in place since 1996 and have not found or observed degraded insulator quality other than "slight" surface contamination, even during periods of excessively dry weather, which would warrant cleaning or other corrective measures. This component history demonstrates that minor contamination is washed away by rainfall or snow, and cumulative buildup has not been experienced and is not expected to occur (with the exception of infrequent storms like Hurricane Isabel). Visual inspection results for high
-voltage insulators are evaluated as part of transmission and distribution outage inspections as well as switchyard system walkdowns. This example provides objective evidence that the aging effect of degraded insulation quality is capable of being detected and that the mechanisms of salt deposit and surface contamination on high
-voltage insulators will be managed prior to loss of intended function. The applicant further stated that the Salem operating experience for the High Voltage Insulators Program provides sufficient confidence that the implementation of the High Voltage Insulators Program will effectively identify degradation prior to failure.
The staff reviewed this information against the acceptance criteria in SRP
-LR Section A.1.2.3.10, which states that operating experience with the existing program should be discussed. The operating experience should provide objective evidence to support the conclusion that the effect of aging will be adequately managed so that the SC intended function(s) will be maintained during the period of extended operation.
The staff finds that although the High Voltage Insulators Program is a new program with no operating experience for implementation, the applicant has captured insulator operating experience through reviewing industry operating experience and onsite documentation. The applicant reviewed industrial as well as plant
-specific operating experience to provide the objective evidence that the new High Voltage Insulators Program will be effective in assuring that the intended function will be maintained consistent with the CLB for 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 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 and, therefore, the staff finds it acceptable.
UFSAR Supplement. LRA Section A.2.2.1 provides the UFSAR supplement for the High Voltage Insulators Program. The staff reviewed this UFSAR supplement description of the program and notes that it conforms to the recommended description for this type of program as described in SRP
-LR Table 3.6-2. The staff notes that the applicant committed Aging Management Review Results 3-171 (Commitment No. 41) to implement the new High Voltage Insulators Program prior to entering the period of extended operation.
The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its technical review of the applicant's High Voltage Insulators Program, the staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained 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  Periodic Inspection Summary of Technical Information in the Application. LRA Section B.2.2.2 describes the new Periodic Inspection Program as a plant
-specific program. The applicant stated that the Periodic Inspection Program manages stainless steel, aluminum, and copper alloy piping and ducting components and tanks for loss of material; heat exchangers for the reduction of heat transfer; and elastomers for hardening and loss of their strength when exposed to wetted (including treated borated water) environments. The applicant also stated that this program will manage cracking of the stainless steel EDG engine exhaust expansion joints. The applicant further stated that the program includes visual inspections and ultrasonic wall thickness measurements to detect loss of material. 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 scope of the Periodic Inspection Program monitors aging effects in stainless steel, aluminum, copper alloy piping, piping components, piping elements, heat exchanger components, tanks and ducting components, and elastomers not included in other AMPs.
The staff reviewed the applicant's "scope of the program" program element against the criteria in SRP-LR Section A.1.2.3.1, which states that the scope of the program should include the specific SCs for which the program manages the aging.
The staff concluded that the scope of the Periodic Inspection Program is consistent with the corresponding element of SRP
-LR Section A.1.2.3.1 because it includes specific SCs for which it will manage aging during the period of extended operation.
The staff confirmed that the "scope of the program" program element satisfies the criterion defined in SRP
-LR Section A.1.2.3.1 and, therefore, the staff finds it acceptable.
 
Aging Management Review Results 3-172 Preventive Actions. LRA Section B.2.2.2 states that the Periodic Inspection Program is a condition monitoring program and does not include activities for prevention or mitigation of aging effects. 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 and thus, this information need not be provided.
The staff concluded that the "preventive actions" element of the Periodic Inspection Program is consistent with the corresponding element of SRP
-LR Section A.1.2.3.2 because the Periodic Inspection Program is a condition monitoring program and does not need to include preventive actions. The staff confirmed that the "preventive actions" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.2 and, therefore, the staff finds it acceptable.
Parameters Monitored or Inspected. LRA Section B.2.2.2 states that the Periodic Inspection Program will detect:  (1) loss of material in stainless steel, aluminum, and copper alloys; (2) hardening and loss of strength in elastomers; (3) cracking of EDG engine exhaust expansion joints; and (4) the presence and extent of fouling that could result in reduction of heat transfer of heat transfer surfaces. The applicant also stated that the program includes provisions for visual inspections and ultrasonic wall thickness measurements to detect loss of material.
The staff reviewed the applicant's "parameters monitored or inspected" program element against the criteria in SRP
-LR Section A.1.2.3.3, which states that the parameters to be monitored or inspected should be identified and linked to the degradation of the particular SCs intended function(s). The SRP
-LR also states that for a condition monitoring program, the parameters monitored or inspected should detect the presence and extent of aging effects.
The staff concluded that the "parameters monitored or inspected" program element of the Periodic Inspection Program is consistent with the corresponding element of SRP
-LR Section A.1.2.3.3 because the applicant identified and linked specific degradations to particular SCs and stated that it will monitor their condition through visual or volumetric inspections, which is appropriate for assuring that they can fulfill their intended functions.
The staff confirmed that the "parameters monitored or inspected" program element satisfies the criterion defined in SRP
-LR Section A.1.2.3.3 and, therefore, the staff finds it acceptable.
Detection of Aging Effects
. LRA Section B.2.2.2 states the Periodic Inspection Program will use visual inspections and ultrasonic wall thickness measurements to detect aging effects of components within the scope of this program prior to loss of their intended function. The visual inspections will focus on:  (1) loss of material in metals identified within the scope of the program; (2) cracking of EDG engine exhaust expansion joints; (3) fouling that could result in reduction of heat transfer on heat exchanger coils; (4) hardening and loss of strength in elastomers, where visual inspections may be augmented by physical manipulations. The applicant also stated that visual inspections and ultrasonic measurements will be performed on a representative sample of components, made available based on system operating conditions, plant operating experience, and accessibility during their periodic disassembly. The applicant further stated that a 10
-year inspection frequency is established based on plant and industry operating experience, which indicates that a 10
-year inspection frequency will be adequate to detect loss of material prior to loss of the component's intended function.
 
Aging Management Review Results 3-173 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 program should:  (1) identify aging effects linked to SCs and monitor these before loss of their intended functions; (2) monitor and inspect appropriate parameters, (3) designate inspection methods, techniques (i.e., visual, volumetric, surface inspection), their frequency, population criteria (i.e., similarity of materials of construction, fabrication, procurement, design, installation, operating environment, or aging effects), sample size (i.e., its basis and bias), data collection, and timing based on plant
-specific or industry
-wide operating experience, (4) maintain the plant's redundancy, diversity, and defense-in-depth consistent with the CLB; and (5) describe "when," "where," and "how" program data is collected.
The staff concluded that a 10
-year inspection frequency is appropriately selected a nd established because it is based on plant
-specific and industry operating experience. After further reviews and comparisons of the "detection of aging effects" program element in LRA Section B.2.2.2 with that of SRP
-LR Section A.1.2.3.4, the staff determined the need for additional clarifications to assess its consistency. This resulted in the issuance of the following RAIs. SRP-LR Appendix A, Section A.1.2.3.4 states that the program element describes "when," "where," and "how" program data will be collected (i.e., all aspects of activities to collect data as part of the program). The "detection of aging effects" program element of the LRA AMP states that the parameters monitored and inspected include visual inspections of component surfaces and ultrasonic wall thickness measurements to identify loss of material. It was not clear to the staff how these techniques would identify loss of material in aluminum components. By a letter dated June 10, 2010, the staff issued RAI B.2.2.2-1 requesting that the applicant explain how visual inspections could identify aging effects in aluminum components. In its response dated July 8, 2010, the applicant stated that aluminum components exposed to air which are included in the Periodic Inspection Program are immune to general corrosion due to the presence of an aluminum oxide layer on the surface of the metal, but that they are subject to loss of material due to pitting and crevice corrosion. The applicant also stated that heat transfer surfaces of aluminum heat exchanger fins and tubes are prone to reduction of heat transfer due to fouling. For both pitting and crevice corrosion and reduction of heat transfer, the applicant stated that it will use visual inspection techniques to identify the appropriate aging effects (i.e., pitting and crevice corrosion by abnormal surface roughness on aluminum component surfaces and detection of fouling by accumulation of dirt, grease, or other foreign material on heat exchanger fins and heat conducting surfaces). The applicant further stated that once these aging effects are identified, they will be noted and addressed through the corrective action program. The staff finds the applicant's response acceptable because visual inspection is an acceptable technique for identifying loss of material due to pitting and crevice corrosion on aluminum components and for identifying fouling on aluminum heat transfer surfaces. The staff's concern described in RAI B.2.2.2-1 is resolved.
When the staff compared the LRA to SRP
-LR Appendix A, Section A.1.2.3.4 regarding the visual inspection and potential physical manipulation of elastomers for hardening and loss of strength, it was not clear to the staff:  (1) what factors would be used to determine the need to augment visual inspections of elastomers with physical manipulations, (2) the characteristics assessed by the physical manipulations, and (3) how collected information would be quantified or otherwise used to assess component longevity. By letter dated June 3, 2010, the staff issued RAI B.2.2.2-2 requesting that the applicant clarify the process for determining the need for physical manipulation of elastomer components to assist visual inspections, clarify the characteristics assessed by the physical manipulations, and discuss how collected information Aging Management Review Results 3-174 would be quantified or otherwise used to assess component longevity. In its response dated July 8, 2010, the applicant stated that elastomer components included in the Periodic Inspection Program are subject to the aging effect of hardening and loss of strength. The applicant stated that physical manipulation to assist in the detection of hardening is determined from the results of the initial visual inspection, which checks the material for cracking, flaking, shrinkage, swelling, or physical damage. The applicant also stated that evidence of aging degradation will lead to that material being placed into the corrective action program. The staff finds the applicant's response acceptable because the applicant has clarified that physical manipulation will be used to verify aging of elastomers if signs of degradation are present, which is an acceptable technique for determining if an elastomer is aging. The staff's concern described in RAI B.2.2.2-2 is resolved.
When the staff compared the LRA to SRP
-LR Appendix A, Section A.1.2.3.4 recommendations on sampling, it was unclear to the staff how the applicant defined its "representative sample,"
population criteria, and population size. On August 18, 2010, the staff held a telephone conference with the applicant (ADAMS Accession No.
ML 102460095) to clarify how the Periodic Inspection Program's sampling methodology, including how the population for each of the material-environment
-aging effect combinations is being selected, and what type of engineering, design, or operating experience considerations would be used to select the sample of components for both the scheduled and supplemental inspections. During this discussion, the applicant stated that the program will ensure that for each material, environment, and aging effect combination, the applicant will conduct representative inspections as directed by formal preventive maintenance or recurring tasks within the work management system. The applicant also stated that the intent is to use existing preventive maintenance or recurring task activities augmented with new recurring task activities to address inspection of material, environments, and aging effects not adequately addressed by the current activities. The applicant further stated that if adverse conditions are identified, the condition will be entered into a corrective action program, discussed in the LRA, and appropriate actions will be directed including identifying and evaluating the cause and extent of the condition(s). The staff finds the applicant's response acceptable and the "detection of aging effects" program element consistent with the corresponding element of SRP
-LR Section A.1.2.3.4 because its "representative sample" will include inspections for each material, environment, and aging effect combination and that when degradation is found, it will be entered in the corrective action program.
The staff confirmed that the "detection of aging effects" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.4 and, therefore, the staff finds it acceptable.
Monitoring and Trending
. LRA Section B.2.2.2 states that the Periodic Inspection Program performs visual inspections for loss of material, loss of strength, hardening, cracking, a nd reduction of heat transfer for selected materials and components, described under the "scope of the program" program element, and ultrasonic wall thickness measurements to detect aging effects. The applicant also stated that these periodic inspections are performed on population samples with frequencies based on industry and plant experience and are effective in identifying the extent of component degradation prior to the loss of their intended function. The applicant further stated that identified degradations will be entered into the corrective action program to determine their impact on the component's intended function, including any required repairs or subsequent monitoring and trending requirements.
The staff reviewed the applicant's "monitoring and trending" program element against the criteria in SRP
-LR Appendix A, Section A.1.2.3.5, which states that monitoring and trending activities should predict the extent of degradation to trigger timely corrective or mitigative Aging Management Review Results 3-175 actions. The SRP
-LR also states that plant
-specific and industry
-wide operating experience may be considered in evaluating appropriate techniques and frequencies. The SRP
-LR further states that the program element should support quantification of aging indicators and parameters monitored to compare ongoing collected data for trending and future predictions.
Following the reviews and comparisons between the LRA Section B.2.2.2 "monitoring and trending" program element with that of SRP
-LR Section A.1.2.3.5, the staff concluded that the applicant's proposed visual inspections and ultrasonic wall thickness measurements together with initiation of corrective actions would be able to determine the extent of degradation and provide timely corrective or mitigative actions because the applicant is:  (1) using techniques that would be able to determine the extent of degradation and (2) has satisfactorily described an appropriate method in which the data will be collected and evaluated.
The staff confirmed that the "monitoring and trending" program element satisfies the criterion defined in SRP
-LR Section A.1.2.3.5 and, therefore, the staff finds it acceptable.
Acceptance Criteria
. LRA Section B 2.2.2 states that the acceptance criteria are based on the following for a given aging effect:  (1) for loss of material, acceptance criteria are based on the original equipment design wall thickness minus allowances for corrosion and degradations; (2) for reduction of heat transfer, acceptance criteria are based on identification of fouling on the external heat transfer surfaces of cooling coils; (3) for standby diesel expansion joint cracking, acceptance criteria are based on preventing exhaust gas leakage that could impact engine operation; and (4) for hardening and loss of strength of elastomers, acceptance criteria are based on visual indications of degradation such as cracking, tears, or perforations in the material, often augmented with physical manipulations to assure the material's integrity or the need for its replacement.
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 so that the need for corrective actions is evaluated. The SRP-LR also states that acceptance criteria should be specific and quantifiable to ensure that the SCs intended function(s) remain (including replacement) under all CLB design conditions during the period of extended operation. The SRP
-LR further states that the program should include a methodology for analyzing the results against applicable acceptance criteria.
The staff reviewed the applicant's "acceptance criteria" program element against the criteria in SRP-LR Appendix A, Section A.1.2.3.6 and determined the need for additional clarifications to assess consistency of the "acceptance criteria" program element, which resulted in the issuance of the following RAI.
SRP-LR Appendix A, Section A.1.2.3.6 states that the acceptance criteria of the program and its basis should be described. In the "acceptance criteria" program element of the LRA AMP, it states that acceptance criteria for loss of material are based on the original equipment design wall thickness and any corrosion allowance requirements. It is not clear to the staff what the acceptance criteria are for determining the effects of aging on aluminum components. By a letter dated June 3, 2010, the staff issued RAI B.2.2.2-3 requesting that the applicant clarify the acceptance criteria for determining the effects of aging on aluminum components. In its response dated July 8, 2010, the applicant stated that focused visual inspections will examine aluminum surfaces and identify:  (1) for loss of material, pitting, or abnormal surface roughness; and (2) for reduction in heat transfer and evidence of surface fouling from the presence of dirt, grease, or other foreign material. The applicant stated that any evidence of this type of Aging Management Review Results 3-176 degradation beyond minor surface corrosion or fouling will be entered into the corrective action program for further engineering evaluation. The applicant also stated that this evaluation will determine a component's acceptability for continued service with acceptance criteria based on the component's design requirements and its intended functions. The applicant further stated that components determined to be incapable of performing their intended function will be repaired or replaced. The staff finds the applicant's response acceptable because the applicant has identified appropriate criteria for determining whether aging is occurring for aluminum components and against which the need for corrective actions will be evaluated. The staff's concern described in RAI B.2.2.2-3 is resolved. The staff concluded that the "acceptance criteria" element of the Periodic Inspection Program is consistent with the corresponding element of SRP
-LR Section A.1.2.3.6 because it includes specific criteria that are appropriate for determining when loss of material, loss of strength, hardening, and cracking are occurring for the components within the scope of the program and for identifying when corrective actions are required. The staff confirmed that the "acceptance criteria" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.6 and, therefore, the staff finds it acceptable.
Operating Experience. LRA Section B.2.2.2 summarizes operating experience related to the Periodic Inspection Program. The applicant stated that the proposed Periodic Inspection
 
Program will be effective in assuring that the intended functions of systems and components within the scope of the program will be maintained for the period of extended operation. To support this statement, the applicant provided several examples of periodic visual inspections including:  (1) stainless steel, aluminum, and copper alloy ventilation system components exposed to plant and outdoor air; (2) stainless steel piping exposed to external salt contamination from the Delaware River, following feedback from industry operating experience observations (INPO SEN 226, "SCC on a Portion of Safety Injection System Piping"); and (3) elastomer components in the fuel handling building exhaust fan. In the first and second examples, the applicant stated that the results of the inspections were satisfactory and that no corrective actions were required. In the third example, the applicant also stated that visual inspection of a degraded elastomer that was previously repaired prompted its replacement. The applicant further stated that these examples demonstrate that these types of inspections performed by system owners are objective and adequate to evaluate the condition of the systems or components.
The staff reviewed this information against the acceptance criteria in SRP-LR Appendix A, Section A.1.2.3.10, which states that 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 SCs 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 woul d not be effective 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 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 and, therefore, the staff finds it acceptable.
 
Aging Management Review Results 3-177 UFSAR Supplement. LRA Section A.2.2.2 provides the UFSAR supplement for the Periodic Inspection Program. The staff reviewed this UFSAR supplement description of the program and notes that it conforms to the recommended description for this type of program as described in SRP-LR Table 3.1-2. The staff also notes that the applicant committed (Commitment No.
: 42) to implement the new Periodic Inspection Program prior to entering the period of extended operation for managing aging of applicable components.
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 technical review of the applicant's Periodic Inspection Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended 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  Aboveground Non
-Steel Tanks Summary of Technical Information in the Application. LRA Section B.2.2.3 describes the new Aboveground Non
-Steel Tanks Program as plant
-specific. The applicant stated that the program is a condition monitoring program that is intended to manage aging of non
-steel tanks. The applicant also stated that the program includes visual inspections of the external tank surfaces above their foundation interface and of the grout and sealant materials at the tank/foundation interface. The applicant further stated that UT will be used to monitor loss of material due to corrosion on tank bottoms. The staff notes that the applicant's inspection procedures ensure that the caulk/sealant joint between the tank and foundation interface is visually inspected during the inspection of the tank.
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.2.2.3 states that all in
-scope aboveground non
-steel tanks are covered in this program. The applicant's coverage of stainless steel in this program is consistent with the GALL Report definition of non
-steel as a construction material being distinguished from carbon steel alloys.
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 SCs for which the program manages aging.
The staff reviewed the LRA and confirmed that the applicant's program has appropriately included non
-steel tanks consistent with the guidance in the SRP
-LR. The staff noted that some non-steel tanks (e.g., volume control tank, boric acid and batching tank, gas decay tanks) are Aging Management Review Results 3-178 managed under different AMPs (e.g., Water Chemistry and Closed
-Cycle Cooling Water System programs). Given that each of the other non
-steel tank AMR line items will be evaluated during the review of the LRA, the staff determines the applicant's scope of the program acceptable for the program managing the aging.
The staff confirmed that the "scope of the program" program element satisfies the criterion defined in SRP
-LR Secti on A.1.2.3.1 and, therefore, the staff finds it acceptable.
Preventive Actions
. LRA Section B.2.2.3 states that the program is a condition monitoring program based on visual inspections and UT of inaccessible tank bottom surfaces. The applicant stated that the program does not include activities for prevention or mitigation of aging effects. 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 monitoring programs, preventive activities do not need to be included in the program.
The staff reviewed the program and confirmed that for the materials (e.g., stainless steel, grout) and environments (e.g., air outdoor, soil) included, it is appropriate that this is a condition monitoring program without activities for corrosion mitigation or for corrosion prevention. Therefore, the staff determines the applicant's preventive actions are appropriate for the program managing the aging.
The staff confirmed that the "preventive actions" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.2 and, therefore, the staff finds it acceptable.
Parameters Monitored or Inspected. LRA Section B.2.2.3 states that the program includes activities to detect the presence and extent of aging effects including general loss of material, pitting, and crevice corrosion prior to the in
-scope tank's loss of intended function. The applicant stated that the methods that monitor for those aging effects are visual inspection and UT. The applicant also stated that UT will quantitatively measure wall thickness of tank bottoms and that information will be used to determine loss of material due to degradation of the internal surface. The applicant further stated that the visual inspection of the grout and sealant materials will detect loss of material.
The staff reviewed the applicant's "parameters monitored or inspected" program element against the criteria in SRP
-LR Section A.1.2.3.3, which states that the parameters to be monitored or inspected should be identified and linked to the degradation of the particular SC intended function(s) and for a condition monitoring program, the parameter monitored or inspected should detect the presence and extent of aging effects.
The staff noted that the use of ultrasonic measurements and visual inspections is consistent with standard industrial practices and the parameters monitored in GALL AMP XI.M29, "Aboveground Steel Tanks," and has been proven to be effective in detecting significant losses of material due to the corrosion effects covered in the applicant's program. Therefore, the staff determines that the parameters to be inspected by the applicant appropriate for the aging effects addressed.
The staff confirmed that the "parameters monitored or inspected" program element satisfies the criterion defined in SRP
-LR Section A.1.2.3.3 and, therefore, the staff finds it acceptable.
 
Aging Management Review Results 3-179 Detection of Aging Effects. LRA Section B.2.2.3 states that direct visual inspection will detect significant loss of material due to pitting and/or crevice corrosion prior to loss of an in
-scope tank's intended functionality. The applicant stated that the UT method will be applied to the inside surfaces to inspect tank bottoms for thickness reduction due to corrosion. The applicant also stated that the visual inspection of the grout and sealant materials will be conducted to detect signs that water could potentially get under the tank bottom. The applicant further stated that the visual inspections will be conducted with 5
-year intervals and that the UT will be conducted for each in
-scope tank bottom prior to the period of extended operation.
The staff reviewed the applicant's "detection of aging effects" program element against the criteria in SRP
-LR Secti on A.1.2.3.4, which states that detection of aging effects should occur before there is a loss of the SC intended function(s). The criteria also states that parameters to be monitored or inspected should be appropriate to ensure that the SC 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 SC 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.
The staff confirmed that the use of the applicant's methods are appropriate for detecting the aging effects covered in the program by comparing them to GALL AMP XI.M29 and that the combined use of visual inspections and UT provide sufficient detection methods to monitor corrosion effects prior to loss of the  tank's intended function. Therefore, the staff determines that the parameters being used to detect the aging effects are appropriate for the aging effects addressed.
The staff confirmed that the "detection of aging effects" program element satisfies the criterion defined in SRP
-LR Section A.1.2.3.4 and, therefore, the staff finds it acceptable.
Monitoring and Trending. LRA Section B.2.2.3 states that the program's visual and ultrasonic examination inspections are based on industry and plant
-specific operating experience. The applicant stated that wall thickness measurements will be compared to design requirements to determine if significant loss of material degradation is occurring. The applicant also stated that any significant corrosion detected as part of the inspections of this program will be entered into the corrective action program to determine the impact on the tank's intended function, required repair, and further monitoring and trending requirements.
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 and/or industry-wide operating experience 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.
The staff considers the applicant's coverage of this program element to be adequate because the applicant's description of the program includes the application of corrosion monitoring and Aging Management Review Results 3-180 engineering analysis when corrosion is detected on in
-scope components, which is consistent with the guidance in the SRP
-LR. While the applicant's program description did not specifically discuss predicting the rate of degradation, it did state that one aspect of the corrective action program is to further monitor and trend requirements. The staff noted that the applicant's monitoring methods are adequate to ensure that corrosion issues can be addressed prior to loss of component functionality because the applicant's method of inspection and frequency of sampling is consistent with industry and plant
-specific operating experience and GALL AMP XI.M29. Therefore, the staff determines that the parameters being monitored or trended are appropriate for the aging effects addressed.
The staff confirmed that the "monitoring and trending" program element satisfies the criterion defined in SRP
-LR Section A.1.2.3.5 and, therefore, the staff finds it acceptable.
Acceptance Criteria. LRA Section B.2.2.3 states that the acceptance criteria for the inspections that result in a quantitative value are the original equipment design wall thickness and corrosion allowance. The applicant stated that the acceptance criteria for visual inspections are qualitative unless indications of significant pitting, crevice corrosion, or other significant degradation are present which will result in an evaluation to quantify the material loss which is then compared to the applicable design requirements. The applicant also stated that inspections are performed by qualified personnel in accordance with approved station procedures.
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, including ensuring that the SC 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 ensure that the SC 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 same predetermined criteria as quantitative inspections by personnel in accordance with ASME Code and through approved site-specific programs.
The staff considers the applicant's coverage of this program element to be adequate because the applicant's program description includes details on the method to be followed in response to observed corrosion effects, which is consistent with the guidance in the SR P-LR. The staff notes that the applicant's program relies on established acceptance criteria, such as the original manufacturer's specifications, including wall thickness for the specific component type and materials to be covered. The staff also notes that qualified personnel are used to perform inspections in accordance with approved plant procedures. Therefore, the staff determines that the acceptance criteria being used to evaluate aging effects are appropriate for the aging effects addressed.
The staff confirmed that the "acceptance criteria" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.6 and, therefore, the staff finds it acceptable.
Operating Experience. LRA Section B.2.2.3 summarizes operating experience related to th e Aboveground Non
-Steel Tanks Program. 
 
Aging Management Review Results 3-181 LRA Section B.2.2.3 summarizes operating experience related to the Aboveground Non
-Steel Tanks Program. In one example of operating experience, the applicant stated that through a process of multiple visual inspections, corrective actions were taken which involved draining a demineralized water storage tank, conducting internal visual inspections and UT, replacing the tank bottom due to a through
-wall hole caused by pitting in the tank bottom, and performing a replacement of the tank bottom on a similar tank as part of the extent of condition review. The applicant also stated that based on industry operating experience, visual inspections were conducted to address the potential for accelerated corrosion due to salt contamination from the Delaware River with resulting visual inspections conducted in 2002, 2006, and 2008 revealing no age-related degradation. The applicant further stated that in over 30 years of operating experience, there has been no degradation of the in-scope tank's external surfaces exposed to the outdoor air environment.
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 SCs are 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 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 and, therefore, the staff finds it acceptable.
UFSAR Supplement. LRA Section A.2.2.3 provides the UFSAR supplement for the Aboveground Non
-Steel Tanks Program.
The staff reviewed this UFSAR supplement description of the program and notes 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 notes that the applicant committed (Commitment No.
: 43) to implement the new Aboveground Non-Steel Tanks Program prior to entering the period of extended operation for managing aging of applicable components.
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 technical review of the applicant's Aboveground Non
-Steel Tanks  Program, the staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained 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 3-182 3.0.3.3.4  Buried Non
-Steel Piping Inspection Summary of Technical Information in the Application. LRA Section B.2.2.4 describes the existing Buried Non
-Steel Piping Inspection as plant
-specific. The applicant stated that the Buried Non
-Steel Piping Inspection Program is a condition monitoring program used to manage buried reinforced concrete piping and components in the service water and circulating water systems as well as the buried stainless steel penetration bellows (a portion of the fuel transfer tube) between the containment structure and the fuel handling building, including the penetration sleeves, exposed to the external soil or groundwater environment for cracking, loss of bond, increase in porosity and permeability, and loss of material. The applicant also stated that the program relies on visual inspections conducted as part of opportunistic and focused excavations of buried, in
-scope piping and components. The applicant further stated that the inspections will identify coating degradation, if coated, or base metal corrosion.
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.2.2.4 states that the Buried Non
-Steel Piping Inspection Program is an existing program that manages the aging effects of cracking, loss of bond, loss of material, and increased porosity and permeability. The applicant stated that the program covers buried reinforced concrete piping and components in the service water and circulating water systems, as well as the buried stainless steel penetration bellows between the containment structure and the fuel handling building, including the penetration sleeves.
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 SCs for which the program manages aging.
The staff reviewed the applicant's description of aging effects and the systems and components to be covered by this program. The staff determines that the LRA provides a list of the specific aging effects to be managed, as well as all component types and systems that are covered by this program.
The staff confirmed that the "scope of the program" program element satisfies the criterion defined in SRP
-LR Section A.1.2.3.1 and, therefore, the staff finds it acceptable.
Preventive Actions. LRA Section B.2.2.4 states that this program is a condition monitoring program that relies on opportunistic and focused inspections and it is not a preventive or mitigative program.
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 monitoring programs, preventive activities do not need to be included in the program.
The staff reviewed the program and confirmed that it is a condition monitoring program withou t activities for corrosion mitigation or for corrosion prevention. The staff notes that the applicant Aging Management Review Results 3-183 stated in the program description, "Inspection of buried components identifies coating degradation, if coated, or base metal corrosion, if uncoated."  The staff determines that whether the pipe coating is credited or not credited does not impact the evaluation of this program in that if it is coated, coating degradation is an inspection parameter.
The staff confirmed that the "preventive actions" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.2 and, therefore, the staff finds it acceptable.
Parameters Monitored or Inspected. LRA Section B.2.2.4 states that the program includes activities to detect the presence and extent of cracking, loss of bond, and increases in porosity and permeability of the in
-scope buried piping and components. The applicant stated that the inspection covers coating degradation if piping or components are coated and base material degradation if piping or components are uncoated. The applicant also stated that this program is not a performance monitoring program nor is it a preventive or mitigative program.
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 SC intended function(s) and for a condition monitoring program, the parameter monitored or inspected should detect the presence and extent of aging effects.
The staff noted that the applicant's intended use of visual inspection is consistent with standard industrial practices and GALL AMP XI.M34, "Buried Piping and Tanks Inspection," and has been proven to be effective in detecting significant losses of material due to the corrosion effects covered in the applicant's program. The staff considers the applicant's coverage of this program element to be adequate because the description of parameters being monitored is sufficient and is consistent with conventional industry parameters applicable for corrosion evaluations.
The staff confirmed that the "parameters monitored or inspected" program element satisfies the criterion defined in SRP
-LR Secti on A.1.2.3.3 and, therefore, the staff finds it acceptable.
Detection of Aging Effects. LRA Section B.2.2.4 states that the use of visual inspections to detect the aging effects being managed by this program is in accordance with accepted industrial standards. The applicant stated that the visual inspection process will, if necessary, include engineering evaluations and the consideration of expanded inspection methods. The applicant also stated in Commitment No. 44 that at least one opportunistic or focused inspection will be performed within 10 years prior to the period of extended operation and within the first 10 years of the period of extended operation. The applicant further stated that plant operating experience (i.e., no failures of buried non
-steel piping due to external aging effects) supports this frequency of inspection.
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 SC intended function(s). The criteria also states that parameters to be monitored or inspected should be appropriate to ensure that the SC 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 SC 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 Aging Management Review Results 3-184 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.
The staff confirmed that the use of the applicant's methods are appropriate for detecting the aging effects covered in the program by comparing them to GALL AMP XI.M34 and that the use of visual inspections provides sufficient detection methods to monitor degradation of coatings and corrosion effects prior to loss of the buried non
-steel piping intended function or failure. Additionally, the program specifies the periodicity of the inspections which are justified by plant-specific operating experience, location of the inspections relative to material type and risk ranking, and inspections will be performed by excavated direct inspection of the pipe.
Therefore, the staff determines that the parameters being used to detect the aging effects are appropriate for the aging effects addressed.
The staff confirmed that the "detection of aging effects" program element satisfies the criterion defined in SRP
-LR Section A.1.2.3.4 and, therefore, the staff finds it acceptable.
Monitoring and Trending. LRA Section B.2.2.4 states that, based on plant
-specific and industry operating experience, opportunistic and focused inspections are appropriate and adequate to detect aging effects prior to piping and components loss of intended function. The applicant stated that significant degradation identified by the visual inspections will be entered into the corrective action program and engineering will quantify the results and either demonstrate acceptability or specify a repair or replacement. The applicant also stated that engineering evaluations will determine the need for follow
-up exams to monitor progression of degradation, ensuring that inspections will occur prior to loss of intended function. The applicant further stated that by trending the data, engineering will determine if the sample size must be expanded to determine the extent of degradation or if the frequency of inspections is acceptable.
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 and/or industry-wide operating experience 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.
The staff considers the applicant's coverage of this program element to be adequate because the applicant's description of the program includes the application of engineering analysis, corrosion monitoring, and trending when corrosion is detected on in
-scope components. The staff notes that the applicant's monitoring and trending methods are adequate to ensure that corrosion issues can be addressed prior to loss of component functionality and inspection frequencies will be adjusted by engineering evaluation, if necessary, based on inspection results. The staff confirmed that the "monitoring and trending" program element satisfies the criterion defined in SRP
-LR Section A.1.2.3.5 and, therefore, the staff finds it acceptable.
Acceptance Criteria. LRA Section B.2.2.4 states that the acceptance criteria to be applied in this program are the applicable regulatory or industry requirements for the respective piping and Aging Management Review Results 3-185 component being inspected. The applicant stated that the specific acceptance criteria relating to localized pipe wall thinning is contained in engineering documents and is used in engineering evaluations of observed corrosion. The applicant also stated that since the visual inspection process and acceptance criteria are qualitative, that in instances where significant corrosion is observed by visual inspection, engineering assessments will be used as well as additional evaluation methods to quantify the material loss and compare it to the applicable design requirements. The applicant further stated that inspections are performed by qualified personnel in accordance with approved procedures.
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, including ensuring that the SC 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 ensure that the SC 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 same predetermined criteria as quantitative inspections by personnel in accordance with ASME Code and through approved site-specific programs.
The staff considers the applicant's coverage of this program element to be adequate because the applicant's program description includes details on the method to be followed in response to observed corrosion effects, it relies on established acceptance design
-based criteria for the specific component and materials to be covered which will be evaluated by engineering, and it relies on standard industry practices. The staff also noted that qualified personnel are used to perform inspections in accordance with approved plant procedures. Therefore, the staff determines that the acceptance criteria being used to evaluate aging effects are appropriate for the aging effects addressed.
The staff confirmed that the "acceptance criteria" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.6 and, therefore, the staff finds it acceptable.
The staff notes that even though the Buried Non-Steel Piping Inspection Program is a plant-specific program, the applicant has demonstrated consistency with each of the program elements in GALL AMP XI.M34 except that the materials are non
-steel (i.e., reinforced concrete, stainless steel) while the scope of GALL AMP XI.M34 includes only steel components (e.g., steel, gray cast iron, ductile cast iron). Based on recent industry operating experience, the staff requires further information related to the applicant's use of cathodic protection and coatings and the quality of backfill in the vicinity of buried pipe.
The staff issued RAIs B.2.1.22 and B.2.1.22-02 and its evaluation is documented in the operating experience program element. The applicant's response to these RAIs may impact the "preventive actions," "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" program elements.
Operating Experience. LRA Section B.2.2.4 summarizes operating experience related to the Buried Non
-Steel Piping Inspection Program. The applicant stated that there have been no underground leaks that developed as a result of failure of the external surface of in
-scope buried piping. The applicant also stated an instance of operating experience that involved the detection of an installation defect when a failed pipe was excavated and an opportunistic Aging Management Review Results 3-186 inspection was conducted. During the audit, the applicant stated that this example of operating experience concerned piping in the service water header joints which are internally inspected once every 3 years, with specific areas of higher susceptibility inspected every 18 months. 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 SCs are maintained during the period of extended operation.
Given that there have been a number of recent industry events involving leakage from buried or underground piping, the staff needs further information to evaluate the impact that these recent industry events might have on the applicant's Buried Piping and Tanks Inspection Program. By letter dated August 6, 2010, the staff issued RAI B.2.1.22 requesting that the applicant provide information regarding how the applicant will incorporate the recent industry operating experience into its AMRs and AMPs.
In its response dated September 7, 2010, the applicant stated that it has risk ranked all buried piping in accordance with NACE and EPRI guidelines and the NEI Industry Initiative on Buried Piping, and based on these risk rankings, inspections of the coating and external surfaces of the pipe are conducted. The applicant also stated that it has committed to conduct excavated visual inspections of at least 8 linear feet, when practical, of buried pipe in each material group prior to entry into the period of extended operation and each 10
-year period after entry into the period of extended operation. The staff notes that based on review of documentation during the audit and subsequent reviews of the LRA application and response to RAIs, all carbon steel piping is coated in accordance with appropriate industry standards.
Based on its review, the staff determined that it does not have sufficient information to find the applicant's response acceptable. By letter dated October 18, 2010, the staff issued follow-up RAI B.2.1.22-02  requesting that the applicant:  (1) define what is meant by excavating 8 feet of pipe when practical, state what alternative inspection means will be used to determine the condition of the buried pipe and its coatings, or justify why inspecting less than 8 feet is sufficient to provide a reasonable assurance of the condition of the pipe and coatings; and (2) provide details on the quality of backfill in the vicinity of in
-scope buried pipes.
The LRA states that the circulating water and service water systems have buried non
-steel piping, as well as the penetration bellows between the containment structure and fuel handling building. Pending the response to RAI B.2.1.22-02, the staff does not have sufficient information to conclude its review of the operating experience program element.
This is tracked as Open Item OI 3.0.3.2.10
-1. UFSAR Supplement. LRA Section A.2.2.4 provides the UFSAR supplement for the Buried Non-Steel Piping Inspection Program. The staff reviewed this UFSAR supplement description of the program and notes that it conforms to the recommended description for this type of program as described in SRP
-LR Table 3.3-2. The staff also notes that the applicant committed (Commitment No.
: 44) to enhance the existing Buried Non
-Steel Piping Inspection Program for managing aging of applicable components during the period of extended operation. Specifically, the applicant committed to perform at least one opportunistic or focused inspection of buried reinforced concrete piping and components and the buried stainless steel penetration bellows between the containment Aging Management Review Results 3-187 structure and the fuel handling building, including the penetration sleeves, within 10 years prior to the period of extended operation and within the first 10 years of the period of extended operation, and enhance the guidance for inspection of concrete aging effects.
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 technical review of the applicant's Non
-Steel Buried Piping Inspection Program, the staff concludes, with the exception of Open Item OI 3.0.3.2.10
-1, 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). 3.0.3.3.5  Boral Monitoring Program Summary of Technical Information in the Application. LRA Section B.2.2.5 describes the existing Boral Monitoring Program as plant
-specific. The applicant stated that the Boral Monitoring Program manages the aging effects of the Boral neutron
-absorbing material used in the Exxon and Holtec spent fuel storage rack assemblies in the Units 1 and 2 spent fuel pools.
The applicant also stated that reduction of neutron
-absorbing capacity and loss of material are the AERMs. The applicant further stated that the program performs inspections and tests on Boral test coupons which simulate as nearly as possible the actual inservice properties of the Boral panels in the spent fuel storage rack assemblies. The applicant stated that the program calls for periodic examination of the test coupons, including visual inspections, weighing, and neutron attenuation testing, and the results of the evaluations are compared to the acceptance criteria for determination of any follow
-up corrective action activities as appropriate. The applicant also stated that there are sufficient test coupons in the spent fuel pool to permit the inspection of the Boral test coupons beyond the period of extended operation for the Exxon and Holtec spent fuel storage rack assemblies.
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.2.2.5 states that the scope of the program includes monitoring of the Boral neutron
-absorbing material in the spent fuel storage rack assemblies at Salem Units 1 and 2. The applicant stated that the program consists of a surveillance program which involves periodic inspections and testing of Boral test coupons that are monitored to ensure against unexpected degradation of the Boral neutron
-absorbing material that are contained in the Units 1 and 2 spent fuel storage rack assemblies. The applicant further stated that the spent fuel pool has three high density Exxon Nuclear Corporation spent fuel storage Aging Management Review Results 3-188 rack assemblies in region I, and nine maximum density Holtec spent fuel storage rack assemblies in region II. The applicant stated that there are three types of Boral test coupons:
There are two types of Boral test coupons utilized in the surveillance program for the Exxon spent fuel storage rack assemblies.  [First test coupon] One type is a flat plate sandwich coupon.  [Second test coupon] The other type is a short fuel Section that is a four sided cube prototype of the actual fuel cell. The flat plate sandwich coupons and short fuel sections are stainless steel clad Boral plate specimens that are of same materials and were produced by using the same manufacturing and Quality Assurance and Quality Control procedures specified for the spent fuel cells within the Exxon spent fuel storage rack assemblies. 
[Third test coupon] The Holtec Boral test coupons are each mounted in a stainless steel jacket simulating as nearly as possible the actual in
-service geometry, physical mounting, materials and flow conditions of the Boral in the spent fuel storage rack assemblies. The Boral is from the same production run as the Boral poison panels in the spent fuel storage rack assemblies. Each Boral test coupon is encased in a stainless steel jacket of the same alloy used in the manufacture of the spent fuel storage rack assemblies mounted with tolerance representative of those in the spent fuel storage rack assemblies.
The staff reviewed the applicant's "scope of the program" program element against the criteria in SRP-LR Section A.1.2.3.1, which states that the scope of the program should include the specific SCs of which the program manages the aging.
The staff confirmed that the "scope of the program" program element satisfies the criterion defined in SRP
-LR Section A.1.2.3.1 and, therefore, the staff finds it acceptable.
Preventive Actions. LRA Section B.2.2.5 states that the program is a condition monitoring program and does not include activities for prevention or mitigation of aging effects. The applicant stated that the program includes activities to periodically inspect for applicable aging effects. The applicant also stated that the Water Chemistry Program will be credited to manage loss of material of the aluminum cladding of the Boral.
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 and thus, this information need not be provided.
The staff confirmed that the "preventive actions" program element satisfies the criterion define d in SRP-LR Section A.1.2.3.2 and, therefore, the staff finds it acceptable.
Parameters Monitored or Inspected. LRA Section B.2.2.5 states that the program performs inspections and tests on Boral test specimens or coupons. The physical properties of the Boral are monitored by performing measurements on representative Boral test coupons. The Boral test coupons are removed in accordance with a prescribed schedule. The applicant stated that the Boral test coupons representative of the Exxon spent fuel storage rack assemblies that are removed from the spent fuel pool are dried and weighed and the coupons undergo visual inspections, looking specifically for corrosion, weld cracks, or leaks. The applicant also stated that benchmark measurements of the coupons are not available from the initial fabrication of the coupons, prior to their placement in the spent fuel pool; as such, physical measurements Aging Management Review Results 3-189 (i.e., length, width, and thickness) are not performed as part of the surveillance inspection. The program will be enhanced to perform neutron attenuation testing of the coupons. After obtaining and recording the results of the inspections, the coupons are returned to the spent fuel pool. Unsatisfactory results are forwarded to the system engineer for evaluation and further action.
The applicant stated that the Boral test coupons representative of the Holtec spent fuel storage rack assemblies that are removed from the spent fuel pool undergo visual inspection, dimensional measurements, weight and specific gravity measurements, and neutron attenuation testing. After obtaining and recording the results of the inspections, the coupons are returned to the spent fuel pool. Unsatisfactory results are forwarded to the system engineer for evaluation and further action.
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 SC intended function(s).
The staff confirmed that the "parameters monitored or inspected" program element satisfies the criterion defined in SRP
-LR Section A.1.2.3.3 and, therefore, the staff finds it acceptable.
Detection of Aging Effects. LRA Section B.2.2.5 states that the program monitors changes in physical properties of the Boral by performing measurements on representative Boral test coupons. The applicant stated that the Boral test coupons simulate as nearly as possible the actual inservice geometry, physical mounting, materials, and flow conditions of the spent fuel pool water for the Boral poison panels in the spent fuel storage rack assemblies. The applicant also stated that each type of spent fuel storage rack assembly has representative test coupons, which are mounted on a specimen assembly or coupon tree suspended in a cell of the spent fuel storage rack assembly. The applicant further stated that the Exxon spent fuel storage rack assemblies have a specimen assembly of 50 Boral test coupons and the Holtec spent fuel storage rack assemblies have a specimen assembly with 10 Boral test coupons.
The applicant stated that every 2 years, 14 Exxon Boral test coupons are retrieved from the specimen assembly for inspections and examinations and returned to the spent fuel pool after completion of inspections. The applicant also stated that the specimen assembly location strategy ensures that the test coupons are placed next to a high burn
-up assembly in the most recently discharged batch of spent fuel assemblies.
The applicant further stated that a Boral test coupon representative of the Holtec spent fuel storage rack assembly is removed every fifth refueling cycle going forward. The applicant also stated that the specimen assembly is located in a cell surrounded by eight of the most recently discharged fuel assemblies.
The applicant stated that the Boral test coupons representative of the Exxon spent fuel storage rack assemblies that are removed from the spent fuel pool are dried and weighed and undergo visual inspections, looking specifically for corrosion, weld cracks, or leaks. The applicant also stated that the inspections will be enhanced to include neutron attenuation testing. The applicant further stated that the Boral test coupons representative of the Holtec spent fuel storage rack assemblies that are removed from the spent fuel pool undergo visual inspection, dimensional measurements, weight and specific gravity measurements, and neutron attenuation testing.
Aging Management Review Results 3-190 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 SC intended function(s). The parameters to be monitored or
 
inspected should be appropriate to ensure that the SC 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 or one
-time inspections to ensure timely detection of aging effects. The program should provide information that links the parameters to be monitored or inspected to the aging effects being manage
: d. The staff confirmed that the "detection of aging effects" program element satisfies the criterion defined in SRP
-LR Section A.1.2.3.4 and, therefore, the staff finds it acceptable.
Monitoring and Trending. LRA Section B.2.2.5 states that monitoring of the Boral neutron-absorbing material is accomplished by performing periodic examination of the Boral test coupons including parameters such as visual observations, dimensional measurements, weight and density determinations, and neutron attenuation testing. The applicant also stated that the results of the examinations are compared to values from pre
-irradiated samples, when available, and previous examinations. The applicant further stated that results are evaluated against acceptance criteria for determination of any further corrective action activities as appropriate and the evaluation reports are maintained to provide a continuing source of data for trend analysis.
The staff reviewed the applicant's "monitoring and trending" program element against the criteria in SRP
-LR Section A.1.2.3.5, which states that monitoring and trending activities should be described and they should provide predictability of the extent of degradation and thus effect timely corrective or mitigative actions. Plant
-specific and industry-wide operating experience may be considered in evaluating the appropriateness of the technique and frequency.
The staff confirmed that the "monitoring and trending" program element satisfies the criterion defined in SRP
-LR Section A.1.2.3.5 and, therefore, the staff finds it acceptable.
Acceptance Criteria. LRA Section B.2.2.5 states that the acceptance criteria of the program for the Holtec spent fuel storage rack assemblies are as follows:
A decrease of no more the 5 percent in Boron
-10 content as determined by neutron attenuation measurements.
An increase in thickness at any point should not exceed 10 percent of the initial thickness at that point.
The acceptance criteria of the program for the Exxon spent fuel storage rack assemblies are a s follows:  Percent Weight Change = [(Specimen Weight
-Weight)/(Weight)] x 100%
Allowable Percent Change = {4% + [(0.1%/yr) x # of yrs in Spent fuel Pool)]}
The applicant stated that the acceptance criteria for the Exxon spent fuel storage rack assemblies will be enhanced to include a decrease of no more than 5 percent in Boron
-10 Aging Management Review Results 3-191 content as determined by neutron attenuation testing. The applicant also stated that the results are compared to archive values from pre
-irradiated samples and with results from previous test coupon examinations, when available, summarized in reports of the surveillance and evaluated against acceptance criteria for determination of any follow
-up corrective action activities as appropriate.
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 SC intended function(s) are maintained under all CLB design conditions during the period of extended operation. The program should include a methodology for analyzing the results against applicable acceptance criteria.
The staff confirmed that the "acceptance criteria" program element satisfies the criterion defined in SRP-LR Section A.1.2.3.6 and, therefore, the staff finds it acceptable.
Operating Experience. LRA Section B.2.2.5 summarizes operating experience related to the Boral Monitoring Program. The applicant provided the following examples of operating experience to demonstrate that the effects of aging are being adequately managed:
  (1) The applicant stated that in 2006, during the performance of the Boral test coupon surveillance of the representative Boral test coupons of the Unit 2 Exxon spent fuel storage rack assemblies, a small corrosion mark which was brownish in color, very small (approximately 0.25 inches in diameter), and the washout trail extended approximately 1 inch down the side of the test coupon was discovered. The applicant also stated that this anomaly was documented in a corrective action report and that the evaluation concluded that this did not represent degradation to the intended function of the Boral neutron-absorbing material of the Exxon spent fuel storage rack assemblies. The applicant further stated that this corrective action report will provide data for trending of inspection results for the Boral Monitoring Program.
  (2) The applicant stated that in 2003, industry operating experience OE21287 was evaluated for potential generic implication at Salem. The applicant also stated that a brief summary of the operating experience was that during the inspection of a Boral test coupon (and two additional coupons as part of the extent of condition) that had been removed from the plant's spent fuel pool, an abnormality was noted in which visual inspection of the one Boral test coupon indicated bulging of the Boral aluminum, cladding that normally encapsulates, and is adhered to, the internal Boron carbide and aluminum composite layer. The applicant further stated that the structural integrity of the clad material had been affected but there has been no evidence of loss or redistribution of the boron carbide in the active poison layer of the Boral material at the time and the inspection yielded no apparent loss of neutron
-absorbing material. The applicant stated that the operating experience report and subsequent 10 CFR Part 21 notification concerning bulging and blistering of a Boral test coupon has had no plant
-specific impact on the test coupon surveillance program and that there has been no evidence of bulging or blistering noted during past inspections.
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 should be discussed. The operating experience of AMPs, including past corrective actions resulting in Aging Management Review Results 3-192 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 SC 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 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 and, therefore, the staff finds it acceptable.
UFSAR Supplement. LRA Section A.2.2.5 provides the UFSAR supplement for the Boral Monitoring Program. The staff reviewed this UFSAR supplement description of the program and has determined that it is acceptable. The staff also notes that the applicant committed (Commitment No.
: 45) to ongoing implementation of the existing Boral Monitoring Program for managing aging of applicable components during the period of extended operation. Particularly, the applicant committed to enhance the program prior to the period of extended operation. The applicant committed to:
  (1) Perform a neutron attenuation measurement on each of the three (no vent holes, one vent holes, and two vent holes) flat plate sandwich Boral test coupons during the first three 2-year inspection frequency periods and every 6 years thereafter for the Exxon spent fuel storage rack assemblies.
  (2) Include acceptance criteria of the neutron attenuation measurement on the Boral test coupons for the Exxon spent fuel storage rack assemblies:  A decrease of no more the 5 percent in Boron
-10 content as determined by neutron attenuation measurements. The benchmark Boron
-10 content used for comparison will be based on the nominal Boron-10 areal density in the design specification.
The staff reviewed the enhancements and determined that they are acceptable because neutron attenuation testing has been determined to be one acceptable means to monitor for loss of material and loss of neutron
-absorbing capability in spent fuel pools during the period of extended operation.
The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion. On the basis of its technical review of the applicant's Boral Monitoring Program, the staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB Aging Management Review Results 3-193 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  Nickel Alloy Aging Management Summary of Technical Information in the Application. Staff Evaluation. The staff reviewed program elements 1 through 6 and 10 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.
GALL Report Table 3.1-1, ID 31 and further evaluation paragraph 3.1.2.2.13 state that the applicant should "provide a commitment in the UFSAR supplement to implement applicable (1) Bulletins and Generic Letters and (2) staff accepted industry guidelines."  The staff notes that such a commitment is not specifically provided in the list of commitments contained in the UFSAR supplement. The list of commitments does, however, contain a commitment to implement the Nickel Alloy Aging Management Program as a whole (Commitment No.
46). The staff also notes that the program (program description section) and the UFSAR supplement description of the program state, "The Nickel Alloy Aging Management program implements applicable NRC Bulletins, Generic Letters and staff
-accepted industry guidelines."  The staff further notes that LRA Section 3.1.2.2.13 states, "Salem complies with applicable NRC Orders and provides a commitment in the UFSAR Supplement to implement applicable (1) Bulletins and Generic Letters and (2) staff
-accepted industry guidelines."  The staff considers these statements to be an adequate indication that the applicant has made the commitment described in the GALL Report because the applicant has committed to its overall Nickel Alloy Aging Management Program and because the program and its descriptions contain statements indicating that the program implements NRC Bulletins, GLs, and staff
-accepted industry guidelines.
Scope of the Program. LRA Section B.2.2.6 states that the Nickel Alloy Aging Management Program manages the cracking of Alloy 600 components. A specific list of components which are, and are not, included in this program is provided.
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 SCs for which the program manages aging.
Based on the exhaustive 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 and, therefore, the staff finds it acceptable.
Preventive Actions
. LRA Section B.2.2.6 states that the Nickel Alloy Aging Management Program includes mitigation activities and strategies to ensure the operability of nickel
-alloy components. This Section cites the MSIP and replacement of Alloy 600/82/182 materials with 690/52/152 materials as two examples of preventive actions.
 
Aging Management Review Results 3-194 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 and, therefore, the staff finds it acceptable.
Parameters Monitored or Inspected. LRA Section B.2.2.6 states that the program monitors for cracking due to SCC through a combination of bare metal visual, surface, and volumetric exams. This Section also states that the components susceptible to cracking are itemized in a database and are subject either to an augmented inspection program or mitigation.
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 SC intended function(s) and for a condition monitoring program, the parameter monitored or inspected should detect the presence and extent of aging effects.
The staff finds that, for the components under consideration, cracking is the degradation mechanism which will affect their intended function and that a combination of visual, surface, and volumetric exams will be capable of detecting cracks.
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 and, therefore, the staff finds it acceptable.
Detection of Aging Effects. LRA Section B.2.2.6 states that bare metal visual, surface, and volumetric exams are used to detect cracking due to SCC in Alloy 600 components. This Section also states that inspection requirements, including frequencies, are contained in ASME Code Section XI and in Code Case N
-722. 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 SC intended function(s). The criteria also states that parameters to be monitored or inspected should be appropriate to ensure that the SC 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 SC 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 bare metal visual, surface, and volumetric test methods were capable of detecting aging prior to loss of intended function. The staff further determined that this element of the AMP refers to the CFR, 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.
 
Aging Management Review Results 3-195 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 and, therefore, the staff finds it acceptable.
Monitoring and Trending. LRA Section B.2.2.6 states that crack dimensions are monitored and trended as part of this program. This Section also states that ASME Code Section XI, Code Case N-722, and MRP
-139 are used to determine inspection techniques and frequencies. This Section further states that all flaws are evaluated and dispositioned in accordance with ASME Code Section XI, Sub Section IWB-3500. This Section finally states that industry operating experience is monitored and incorporated, as necessary, into this AMP.
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 and/or industry-wide operating experience 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 which is proposed. The staff also determined that the governing documents for the inspections to be monitored and trended provide sufficient guidance to provide timely corrective action prior to loss of intended function. This guidance includes information concerning inspection frequency and the modification of that frequency
-based plant-specific or industry operating experience. The staff further determined that the program element and the governing documents provide 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 and, therefore, the staff finds it acceptable.
Acceptance Criteria. LRA Section B.2.2.6 states that acceptance criteria for this program are contained in governing documents (ASME Code Section XI, SubSection IWB 3640 and WCAP-15657-P). This Section also states that inspection results are dispositioned as being acceptable to permit continued operation or corrective action is initiated.
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, including ensuring that the SC 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 ensure that the SC 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 same predetermined criteria as Aging Management Review Results 3-196 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 and, therefore, the staff finds it acceptable.
Operating Experience. LRA Section B.2.2.6 summarizes operating experience related to the Nickel Alloy Aging Management Program. In this program element, the applicant provided a detailed list of components which have been inspected. These inspections resulted in no flaws being found, the component being proactively replaced, or the component being subjected to mechanical stress improvement.
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 SCs are maintained during the period of extended operation.
In its review, the staff noted that the applicant responded to the potential for cracks or the discovery of cracks in a number of different ways. In each case, the staff considers the approach used to be appropriate for the circumstances. The staff views this variability in approach as indicting that the applicant's AMP is an effective tool in identifying and responding to cracking or the threat of cracking of nickel alloys.
Based on its review, 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 and, therefore, the staff finds it acceptable.
UFSAR Supplement. LRA Section A.2.2.6 provides the UFSAR supplement for the Nickel Alloy Aging Management Program. The staff reviewed this UFSAR supplement description of the program and notes that it provides an adequate description of the program.
The staff determines that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d). Conclusion
. On the basis of its technical review of the applicant's Nickel Alloy Aging Management Program, the staff concludes that the applicant has demonstrated that, through the use of this AMP, the effects of aging of nickel alloys may 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 Aging Management Review Results 3-197 also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d). 3.0.4  Quality Assurance Program Attributes Integral to Aging Management Programs 3.0.4.1  Summary of Technical Information in Application In LRA Appendix A, "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," the applicant described the elements of corrective actions, confirmation process, and administrative controls that are applied to the AMPs for both safety
-related and nonsafety
-related components. The Salem quality assurance program (QAP) is used which includes the elements of corrective actions, 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. LRA Appendix A, Section A.1.5 and Appendix B, Section B.1.3 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 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. Three of these ten attributes are associated with the quality assurance (QA) activities of corrective actions, 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:
  (1) Attribute No.
7 - Corrective actions, including root cause determination and prevention of recurrence, should be timely.
  (2) Attribute No.
8 - Confirmation process, which should ensure that preventive actions are adequate and that appropriate corrective actions have been completed and are effective.
  (3) 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 actions, confirmation process, and administrative controls. Branch Technical Position IQMB
-1 provides the following guidance with regard to the QA attributes of AMPs:
 
Aging Management Review Results 3-198 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 LRA Appendix A and Appendix B and the associated implementing procedures. The purpose of this review was to ensure that the QA attributes (corrective actions, 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 LRA Appendix A, Section A.1.5 and Appendix B, Section B.1.3 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 LRA Appendix A, Section A.1.5 and Appendix B, Section B.1.3 were determined to be consistent with the staff's position regarding QA for aging management. The staff concludes that the QA attributes (corrective actions, confirmation process, and administrative controls) of the applicant's AMPs are consistent with 10 CFR 54.21(a)(3).
3.1  Aging Management of Reactor Vessel, Internals, and Reactor Coolant System This Section of the SER documents the staff's review of the applicant's AMR results for the reactor vessel, reactor vessel internals, and RCS components and component groups of the following:
reactor coolant system reactor vessel reactor vessel internals steam generator 3.1.1  Summary of Technical Information in the Application LRA Section 3.1 provides AMR results for the RCS, reactor vessel, reactor vessel internals, 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, reactor vessel internals, and steam generator components and component groups.
 
Aging Management Review Results 3-199 The applicant's AMRs evaluated and incorporated applicable plant
-specific and industry operating experience in the determination of AERMs. The plant
-specific evaluation include d 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 Repor
: t. 3.1.2  Staff Evaluation The staff reviewed LRA Section 3.1 to determine whether the applicant provided sufficient information to demonstrate that the effects of aging for the RCS, reactor vessel, reactor vessel internals, and steam generator components within the scope of license renewal and subject to an AMR will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3).
The staff conducted an onsite audit of the applicant's AMPs to ensure the applicant's claim that certain AMPs were consistent with the GALL Report. The purpose of this audit was to examine the applicant's AMPs and related documentation and to verify the applicant's claim of consistency with the corresponding GALL Report AMPs. The staff did not repeat its review of the matters described in the GALL Report. The staff's evaluations of the AMPs are documented in SER Section 3.0.3. The staff reviewed the AMRs to confirm the applicant's claim that certain identified AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant had identified the appropriate GALL Report AMRs. Details of the staff's evaluation are discussed in SER Sections 3.1.2.1 and 3.1.2.2.
The staff also reviewed the AMRs not consistent with or not addressed in the GALL Report.
The review evaluated whether all plausible aging effects were identified and whether the aging effects listed were appropriate for the combination of materials and environments specified. Details of the staff's evaluation are discussed in SER Section 3.1.2.3. For components which the applicant claimed were not applicable or required no aging management, the staff reviewed the AMR line items and the plant's operating experience to verify the applicant's claims.
Table 3.1-1 summarizes the staff's evaluation of components, aging effects or mechanisms, and AMPs listed in LRA Section 3.1 and addressed in the GALL Report.
 
Aging Management Review Results 3-200 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 3.1.2.2.1)
Steel; stainless steel; steel with nickel
-alloy or stainless steel cladding; nickel
-alloy reactor vessel components: flanges; nozzles; penetrations; safe ends; thermal sleeves; vessel shells, heads, and welds (3.1.1-2) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) and environmental effects are to be addressed for Class 1 components Yes Not applicable Not applicable to PWRs (see SER Section 3.1.2.2.1)
Steel; stainless steel; steel with nickel
-alloy or stainless steel cladding; nickel
-alloy RCPB piping, piping components, and piping elements exposed to reactor coolant (3.1.1-3) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) and environmental effects are to be addressed for Class 1 components Yes Not applicable Not applicable to PWRs (see SER Section 3.1.2.2.1)
Steel pump and valve closure bolting (3.1.1-4) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) check Code limits for allowable cycles (less than 7,000 cycles) of thermal stress range Yes Not applicable Not applicable to PWRs (see SER Section 3.1.2.2.1)
Stainless steel and nickel-alloy reactor vessel internals components (3.1.1-5) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) Yes TLAA Fatigue is a TLAA (see SER Section 3.1.2.2.1)
Nickel-alloy tubes and sleeves in a reactor coolant and secondary feedwater/steam environment (3.1.1-6) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) Yes TLAA Fatigue is a TLAA (see SER Section 3.1.2.2.1)
 
Aging Management Review Results 3-201 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel and stainless steel RCPB closure bolting, head closure studs, support skirts and attachment welds, pressurizer relief tank components, steam generator components, piping and components external surfaces and bolting (3.1.1-7) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) Yes TLAA Fatigue is a TLAA (see SER Section 3.1.2.2.1)
Steel; stainless steel; and nickel
-alloy RCPB piping, piping components, piping elements; flanges; nozzles and safe ends; pressurizer vessel shell heads and welds; heater sheaths and sleeves; penetrations; and thermal sleeves (3.1.1-8) Cumulative fatigue damage TLAA, evaluated i n accordance with 10 CFR 54.21(c) and environmental effects are to be addressed for Class 1 components Yes TLAA Fatigue is a TLAA (see SER Section 3.1.2.2.1)
Steel; stainless steel; steel with nickel
-alloy or stainless steel cladding; nickel
-alloy reactor vessel components: flanges; nozzles; penetrations; pressure housings; safe ends; thermal sleeves; vessel shells, heads, and welds (3.1.1-9) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) and environmental effects are to be addressed for Class 1 components Yes TLAA Fatigue is a TLAA (see SER Section 3.1.2.2.1)
Steel; stainless steel; steel with nickel
-alloy or stainless steel cladding; nickel
-alloy steam generator components (flanges; penetrations; nozzles; safe ends, lower heads, and welds) (3.1.1-10) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) and environmental effects are to be addressed for Class 1 components Yes TLAA Fatigue is a TLAA (see SER Section 3.1.2.2.1)
 
Aging Management Review Results 3-202 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel top head enclosure (without cladding) top head nozzles (vent, top head spray or reactor core isolation cooling (RCIC), and spare) exposed to reactor coolant (3.1.1-11) Loss of material due to general, pitting, and crevice corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (see SER Section 3.1.2.2.2)
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 Inspecti on Yes Water Chemistry and Steam  Generator Tube Integrity Consistent with the GALL Report (see SER Section 3.1.2.2.2(1))
Steel and stainless steel isolation condenser components exposed to reactor coolant (3.1.1-13) Loss of material due to general (steel only),
pitting, and crevice corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (see SER Section 3.1.2.2.2(2))
Stainless steel, nickel alloy, and steel with nickel
-alloy or stainless steel cladding reactor vessel flanges, nozzles, penetrations, safe ends, vessel shells, heads, and welds (3.1.1-14) Loss of material due to pitting and crevice corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (see SER Section 3.1.2.2.2(3))
Stainless steel; steel with nickel
-alloy or stainless steel cladding; and nickel-alloy 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 Y es Not applicable Not applicable to PWRs (see SER Section 3.1.2.2.2(3))
 
Aging Management Review Results 3-203 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel steam generator upper and lower shell and transition cone exposed to secondary feedwater and steam (3.1.1-16) Loss of material due to general, pitting, and crevice corrosion Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry and, for Westinghouse Model 44 and 51 S/G, if general and pitting corrosion of the shell is known to exist, additional inspection procedures are to be developed.
Yes ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD; Water Chemistry; and Steam Generator Tube Integrity Consistent with the GALL Report (see SER Section 3.1.2.2.2(4))
Steel (with or without stainless steel cladding) reactor vessel beltline shell, nozzles, and welds (3.1.1-17) Loss of fracture toughness due to neutron irradiation embrittlement TLAA, evaluated in accordance with 10 CFR Part 50, Appendix G and RG 1.99. The applicant may choose to demonstrate that the materials of the nozzles are not controlling for the TLAA evaluations.
Yes TLAA Loss of fracture toughness due to neutron irradiation embrittlement is a TLAA (see SER Section 3.1.2.2.3(1))
Steel (with or without stainless steel cladding) reactor vessel beltline shell, nozzles, and welds; safety injection nozzles (3.1.1-18) Loss of fracture toughness due to neutron irradiation embrittlement Reactor Vessel Surveillance Yes Reactor Vessel Surveillance Consistent with the GALL Report (see SER Section 3.1.2.2.3(2))
Stainless steel and nickel-alloy top head enclosure vessel flange leak detection line (3.1.1-19) Cracking due to SCC and intergranular stress-corrosion cracking (IGSCC) A plant-specific AMP is to be evaluated.
Yes Not applicable Not applicable to PWRs (see SER Section 3.1.2.2.4(1))
Stainless steel isolation condenser components exposed to reactor coolant (3.1.1-20) Cracking due to SCC and IGSCC Inservice Inspection (IWB, IWC, and IWD), Water Chemistry, and pla nt-specific verification program Yes Not applicable Not applicable to PWRs (see SER Section 3.1.2.2.4(2))
Reactor vessel shell fabricated of SA508-Cl 2 forgings clad with stainless steel using a high-heat-input welding process (3.1.1-21) Crack growth
 
due to cyclic loading TLAA Yes Not applicable Not applicable to Salem (see SER Section 3.1.2.2.5)
 
Aging Management Review Results 3-204 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel and nickel-alloy reactor vessel internals components exposed to reactor coolant and neutron flux (3.1.1-22) Loss of fracture toughness due to neutron irradiation embrittlement, void swelling UFSAR supplement commitment to:  (1) participate in industry reactor vessel internals AMPs, (2) implement applicable results, (3) submit for NRC approval
> 24 months before the period of extended operation a reactor vessel internals inspection plan based on industry recommendation.
No, but licensee commitment needs to be confirmed PWR Vessel Internals  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 (BMI) guide tubes (3.1.1-23) Cracking due to SCC A plant-specific AMP is to be evaluated.
Yes ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Consistent with the GALL Report (see SER Section 3.1.2.2.7(1))
CASS Class 1 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 Water Chemistry and Thermal Aging Embrittlement of CASS Consistent with the GALL Report (see SER Section 3.1.2.2.7(2))
Stainless steel jet pump sensing line (3.1.1-25) Cracking due to cyclic loading A plant-specific AMP is to be evaluated.
Yes Not applicable Not applicable to PWRs (see SER Section 3.1.2.2.8(1))
Steel and stainless steel isolation condenser components exposed to reactor coolant (3.1.1-26) Cracking due to cyclic loading Inservice Inspection (IWB, IWC, and IWD) and plant-specific verification program Yes Not applicable Not applicable to PWRs (see SER Section 3.1.2.2.8(2))
 
Aging Management Review Results 3-205 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel and nickel-alloy reactor vessel internals screws, bolts, tie rods, and hold
-down springs (3.1.1-27) Loss of preload due to stress relaxation UFSAR supplement commitment to:  (1) participate in industry reactor vessel internals AMPs, (2) implement applicable results, (3) submit for NRC approval > 24 months before the period of extended operation a reactor vessel internals inspection plan based on industry recommendation.
No, but licensee commitment needs to be confirmed PWR Vessel Internals 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 Not applicable to Salem (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 3.1.2.2.11)
 
Aging Management Review Results 3-206 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel reactor vessel internals components (e.g., upper internals assembly, rod cluster control assembly (RCCA) guide tube assemblies, baffle/former assembly, lower internal assembly, shroud assemblies, plenum cover and plenum cylinder, upper grid assembly, control rod guide tube 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 irradiation
- assisted stress-corrosion cracking (IASCC) Water Chemistry and UFSAR supplement commitment to:  (1) participate in industry reactor vessel internals AMPs, (2) implement applicable results, (3) submit for NRC approval < 24 months before the period of extended operation a reactor vessel internals inspection plan based on industry recommendation.
No, but licensee commitment needs to be confirmed PWR Vessel Internals and Water Chemistry Consistent with the GALL Report (see SER Section 3.1.2.2.12)
Nickel alloy and steel with nickel
-alloy cladding piping, piping component, piping elements, penetrations, nozzles, safe ends, and welds (other than reactor vessel head); pressurizer heater sheaths, sleeves, diaphragm plate, manways and flanges; core support pads/core guide lugs (3.1.1-31) Cracking due to PWSC C Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry and UFSAR supplement commitment to implement applicable plant commitments to:  (1) NRC Orders, Bulletins, and GLs associated with nickel alloys and (2) staff-accepted industry guidelines.
No, but licensee commitment needs to be confirmed ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD; Nickel Alloy Aging Management; and Water Chemistry  Consistent with the GALL Report (see SER Secti on 3.1.2.2.13)
Steel steam generator feedwater inlet ring and supports (3.1.1-32) Wall thinning due to flow-accelerated corrosion A plant-specific AMP is to be evaluated.
Yes Steam Generator Tube Integrity Consistent with the GALL Report (see SER Section 3.1.2.2.14)
 
Aging Management Review Results 3-207 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel and nickel-alloy reactor vessel internals components (3.1.1-33) Changes in dimensions due to void swelling UFSAR supplement commitment to:  (1) participate in industry reactor vessel internals AMPs, (2) implement applicable results, (3) submit for NRC approval > 24 months before the period of extended operation a reactor vessel internals inspection plan based on industry recommendation.
No, but licensee commitment needs to be confirmed PWR Vessel Internals Consistent with the GALL Report (see SER Section 3.1.2.2.15)
Stainless steel and nickel-alloy reactor control rod drive (CRD) head penetration pressure housings (3.1.1-34) Cracking due to SCC and PWSCC Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry and for nickel alloy, comply with applicable NRC Orders and provide a commitment in the UFSAR supplement to implement applicable: (1) Bulletins and GLs and (2) staff-accepted industry guidelines.
No, but licensee commitment needs to be confirmed ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD and Water Chemistry Consistent with the GALL Report (see SER Section 3.1.2.2.16(1))
Steel with stainless steel or nickel
-alloy cladding primary
-side components; steam generator upper and lower heads, tubesheets and tube-to-tubesheet welds (3.1.1-35) Cracking due to SCC and PWSCC Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry and for nickel alloy, comply with applicable NRC Orders and provide a commitment in the UFSAR supplement to implement applicable:  (1) Bulletins and GLs and (2) staff-accepted industry guidelines.
No, but licensee commitment needs to be confirmed Not applicable Not applicable to Salem (see SER Section 3.1.2.2.16(1))
 
Aging Management Review Results 3-208 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Nickel-alloy, stainless steel pressurizer spray head (3.1.1-36) Cracking due to SCC and PWSCC Water Chemistry and One-Time Inspection and, for nickel-alloy welded spray heads, comply with applicable NRC Orders and provide a commitment in the UFSAR supplement to implement applicable: (1) Bulletins and GLs and (2) staff-accepted industry guidelines.
No, but licensee commitment needs to be confirmed One-Time Inspection and Water Chemistry Consistent with the GALL Report (see SER Section 3.1.2.2.16(2))
Stainless steel and nickel-alloy reactor vessel internals components (e.g., upper internals assembly, RCCA guide tube assemblies, lower internal assembly, control element assembly (CEA) shroud assemblies, core shroud assembly, core support shield assembly, core barrel assembly, lower grid assembly, and flow distributor assembly) (3.1.1-37) Cracking due to SCC, PWSCC, and IASCC Water Chemistry and UFSAR supplement commitment to:  (1) participate in industry reactor vessel internals AMPs, (2) implement applicable results, (3) submit for NRC approval > 24 months before the period of extended operation a reactor vessel internals inspection plan based on industry recommendation.
No, but licensee commitment needs to be confirmed PWR Vessel Internals and Water Chemistry Consistent with the GALL Report (see SER Section 3.1.2.2.17)
Steel (with or without stainless steel cladding) CRD return line nozzles exposed to reactor coolant (3.1.1-38) Cracking due to cyclic loading BWR Control Rod Drive Return Line Nozzle No 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 3-209 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel and nickel-alloy penetrations for CRD stub tubes instrumentation, jet pump instrumentation, 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 nickel-alloy piping, piping components, and piping elements NPS; nozzle safe ends and associated welds (3.1.1-41) Cracking due to SCC and IGSCC BWR Stress Corrosion Cracking and Water Chemistry No Not applicable Not applicable to PWRs (see SER Section 3.1.2.1.1)
Stainless steel and nickel-alloy vessel shell attachment welds exposed to reactor coolant (3.1.1-42) Cracking due to SCC and IGSCC BWR Vessel ID Attachment Welds and Water Chemistry No Not applicable Not applicable to PWRs (see SER Section 3.1.2.1.1)
Stainless steel fuel supports and CRD assemblies CRD housing exposed to reactor coolant (3.1.1-43) Cracking due to SCC and IGSCC BWR Vessel Internals and Water Chemistry No Not applicable Not applicable to PWRs (see SER Section 3.1.2.1.1)
Stainless steel and nickel-alloy core shroud, core plate, core plate bolts, support structure, top guide, core spray lines, spargers, jet pump assemblies, CRD housing, 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)
Steel piping, piping components, and piping elements exposed to reactor coolant (3.1.1-45) Wall thinning due to flow-accelerated corrosion Flow-Accelerated Corrosion No Not applicable Not applicable to PWRs (see SER Section 3.1.2.1.1)
 
Aging Management Review Results 3-210 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Nickel-alloy core shroud and core plate access hole cover (mechanical covers) (3.1.1-46) Cracking due to SCC, IGSCC, and IASCC Inservice Inspection (IWB, IWC, and IWD), and Water Chemistry No Not applicable Not applicable to PWRs (see SER Section 3.1.2.1.1)
Stainless steel and nickel-alloy reactor vessel internals exposed to reactor coolant (3.1.1-47) Loss of material due to pitting and crevice corrosion Inservice Inspection (IWB, IWC, and IWD), and Water Chemistry No Not applicable Not applicable to PWRs (see SER Section 3.1.2.1.1)
Steel and stainless steel Class 1 piping, fittings, and branch connections less than 4 NPS exposed to reactor coolant (3.1.1-48) Cracking due to SCC, IGSCC (for stainles s steel only), and thermal and mechanical loading Inservice Inspection (IWB, IWC, and IWD), Water Chemistry, and One-Time Inspection of ASME Code Class 1 Small-Bore Piping No Not applicable Not applicable to PWRs (see SER Section 3.1.2.1.1)
Nickel-alloy core shroud and core plate access hole cover (welded covers) (3.1.1-49) Cracking due to SCC, IGSCC, and IASCC Inservice Inspection (IWB, IWC, and IWD), Water Chemistry, and, for BWRs with a crevice in the access hole covers, augmented inspection using UT or other demonstrated acceptable inspection of the access hole cover welds No 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; orificed fuel support (3.1.1-51) Loss of fracture toughness due to thermal aging and neutro n 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)
 
Aging Management Review Results 3-2 11 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel and stainless steel RCPB 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 and Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Consistent with the GALL Report (see SER Section 3.1.2.1.2)
Steel piping, piping components, and piping elements exposed to closed-cycle cooling water (3.1.1-53) Loss of material due to general, pitting, and crevice corrosion Closed-Cycle Cooling Water System No Not applicable Not applicable to Salem (see SER Section 3.1.2.1.1)
Copper alloy piping, piping components, and piping elements exposed to closed-cycle cooling water (3.1.1-54) Loss of material due to pitting, crevice, and galvanic corrosion Closed-Cycle Cooling Water System No Not applicable Not applicable to Salem (see SER Section 3.1.2.1.1)
CASS Class 1 pump casings and valve bodies and bonnets exposed to reactor coolant > 250 &deg;C (482 &deg;F) (3.1.1-55) Loss of fracture toughness due to thermal aging embrittlement Inservice Inspection (IWB, IWC, and IWD). Thermal aging susceptibility screening is not necessary, inservice inspection requirements are sufficient for managing these aging effects. ASME Code Case N-481 also provides an alternative for pump casings. No ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Consistent with the GALL Report (see SER Section 3.1.2.1.3)
Copper alloy greater than 15% zinc (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 Salem (see SER Section 3.1.2.1.1)
 
Aging Management Review Results 3-212 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation CASS Class 1 piping, piping components, and piping elements and CRD pressure housings exposed to reactor coolant
> 250 &deg;C (482 &deg;F) (3.1.1-57) Loss of fracture toughness due to thermal aging embrittlement Thermal Aging Embrittlement of CASS No Thermal Aging Embrittlement of CASS Consistent with the GALL Report 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 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-accelerated corrosion Flow-Accelerated Corrosion No Flow-Accelerated Corrosion 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 Flux Thimble Tube Inspection Consistent with the GALL Report Stainless steel, steel pressurizer integral support exposed to air with metal temperature up to 288 &deg;C (550 &deg;F) (3.1.1-61) Cracking due to cyclic loading Inservice Inspection (IWB, IWC, and IWD)
No ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 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 Inservice Inspection (IWB, IWC, and IWD)
No ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Consistent with the GALL Report
 
Aging Management Review Results 3-213 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel reactor vessel flange, stainless steel and nickel
-alloy reactor vessel internals exposed to reactor coolant (e.g., upper and lower internals assembly, CEA shroud assembly, core support barrel, upper grid assembly, core support shield assembly, and lower grid assembly)
(3.1.1-63) Loss of material due to wear Inservice Inspection (IWB, IWC, and IWD)
No ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Consistent with the GALL Report Stainless steel and steel with stainless steel or nickel
-alloy cladding pressurizer components (3.1.1-64) Cracking due to SCC and PWSCC Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry No ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD and Water Chemistry Consistent with the GALL Report Nickel-alloy reactor vessel upper head and CRD penetration nozzles, instrumen t tubes, head vent pipe (top head), and welds (3.1.1-65) Cracking due to PWSCC Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry and Nickel
-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors No  ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD; Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors; and Water Chemistry Consistent with the GALL Report Steel steam generator secondary manways and handholds (cover only) exposed to air with leaking secondary-side water and/or steam (3.1.1-66) Loss of material due to erosion Inservice Inspection (IWB, IWC, and IWD) for Class 2 components No Not applicable Not applicable to Salem (see SER Section 3.1.2.1.1)
Steel with stainless steel or nickel
-alloy cladding; or stainless steel pressurizer components exposed to reactor coolant (3.1.1-67) Cracking due to cyclic loading Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry No  ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD and Water Chemistry Consistent with the GALL Report
 
Aging Management Review Results 3-214 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation 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 fitting s (3.1.1-68) Cracking due to SCC Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry No  ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD and Water Chemistry Consistent with the GALL Report Stainless steel, nickel-alloy safety injection nozzles, safe ends, and associated welds and buttering exposed to reactor coolant (3.1.1-69) Cracking due to SCC and PWSCC Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry No  ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD and Water Chemistry Consistent with the GALL Report Stainless steel; steel with stainless steel cladding Class 1 piping, fittings, and branch connections less than 4 NPS exposed to reactor coolant (3.1.1-70) Cracking due to SCC and thermal and mechanical loading Inservice Inspection (IWB, IWC, and IWD), Water Chemistry, and One-Time Inspection of ASME Code Class 1 Small-Bore Piping No  ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD; Water Chemistry; and One-Time Inspection of ASME Code Class 1 Small-Bore Piping 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; loss of material due to wear Reactor Head Closure Studs No Reactor Head Closure Studs Consistent with the GALL Report Nickel-alloy steam generator tubes and sleeves exposed to secondary feedwater/steam (3.1.1-72) Cracking due to outside-diameter stress-corrosion cracking (ODSCC) and intergranular attack, loss of material due to fretting and wear Steam Generator Tube Integrity and Water Chemistry No Steam Generator Tube Integrity and Water Chemistry Consistent with the GALL Report
 
Aging Management Review Results 3-215 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Nickel-alloy steam generator tubes, 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 and Water Chemistry Consistent with the GALL Report Chrome plated steel, stainless steel, nickel-alloy steam generator anti-vibration bars exposed to secondary feedwater/steam (3.1.1-74) Cracking due to SCC, loss of material due to crevice corrosion and fretting Steam Generator Tube Integrity and Water Chemistry No Steam Generator Tube Integrity and Water Chemistry Consistent with the GALL Report Nickel-alloy once-through steam generator tubes exposed to secondary feedwater/steam (3.1.1-75) Denting due to corrosion of carbon steel tube support plate Steam Generator Tube Integrity and Water Chemistry No Not applicable Not applicable to Salem (see SER Section 3.1.2.1.1)
Steel steam generator tube support plate, tube bundle wrapper exposed to secondary feedwater/steam (3.1.1-76) Loss of material due to erosion, general, pitting, and crevice corrosion, ligament cracking due to corrosion Steam Generator Tube Integrity and Water Chemistry No Steam Generator Tube Integrity and Water Chemistry Consistent with the GALL Report Nickel-alloy steam generator tubes and sleeves exposed to phosphate chemistry in secondary feedwater/steam (3.1.1-77) Loss of material due to wastage and pitting corrosion Steam Generator Tube Integrity and Water Chemistry No Not applicable Not applicable to Salem (see SER Section 3.1.2.1.1)
Steel steam generator tube support lattice bars exposed to secondary feedwater/steam (3.1.1-78) Wall thinning due to flow-accelerated corrosion Steam Generator Tube Integrity and Water Chemistry No Not applicable Not applicable to Salem (see SER Section 3.1.2.1.1)
 
Aging Management Review Results 3-216 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Nickel-alloy steam generator tubes exposed to secondary feedwater/steam (3.1.1-79) Denting due to corrosion of steel tube support plate Steam Generator Tube Integrity, Water Chemistry and, for plants that could experience denting at the upper support plates, evaluate potential for rapidly propagating cracks and then develop and take corrective actions consistent with NRC Bulletin 88-02. No Not applicable Not applicable to Salem (see SER Section 3.1.2.1.1)
CASS reactor vessel internals (e.g., upper internals assembly, lower internal assembly, CEA shroud assemblies, control rod guide tube assembly, core support shield assembly, and 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 PWR Vessel Internals Consistent with the GALL Report (see SER Section 3.1.2.1.4)
Nickel alloy or nickel-alloy clad steam generator divider plate exposed to reactor coolant (3.1.1-81) Cracking due to PWSCC Water Chemistry No Water Chemistry Consistent with the GALL Report (see SER Section 3.1.2.1.5)
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 Sal em (see SER Section 3.1.2.1.1)
Stainless steel; steel with nickel
-alloy or stainless steel cladding; and nickel-alloy reactor vessel internals and RCPB components exposed to reactor coolant (3.1.1-83) Loss of material due to pitting and crevice corrosion Water Chemistry No Water Chemistry Consistent with the GALL Report
 
Aging Management Review Results 3-217 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Nickel-alloy steam generator components such as secondary-side nozzles (vent, drain, and instrumentation) exposed to secondary feedwater/steam (3.1.1-84) Cracking due to SCC Water Chemistry and One-Time Inspection or Inservice Inspection (IWB, IWC, and IWD)
No Not applicable Not applicable to Salem (see SER Section 3.1.2.1.1)
Nickel-alloy piping, piping components, and piping elements exposed to air
-indoor uncontrolled (external)
(3.1.1-85) None None NA 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 NA None Consistent with the GALL Report Steel piping, piping components, and piping elements in concrete (3.1.1-87) None None NA None Not applicable to Salem (see SER Section 3.1.2.1.1)
The staff's review of the RCS component groups followed several approaches. One approach, documented in SER Section 3.1.2.1, discusses the staff's review of AMR results for components the applicant indicated are consistent with the GALL Report and require no further evaluation. Another approach, documented in SER Section 3.1.2.2, discusses the staff's review of AMR results for components the applicant indicated are consistent with the GALL Report and for which further evaluation is recommended. A third approach, documented in SER Section 3.1.2.3, discusses the staff's review of AMR results for components the applicant indicated are not consistent with or not addressed in the GALL Report. The staff's review of AMPs credited to manage or monitor aging effects of the RCS components is documented in SER Section 3.0.3. 3.1.2.1  AMR Results That Are Consistent with the GALL Report LRA Section 3.1.2.1 identifies the materials, environments, AERMs, and the following programs that manage aging effects for the reactor vessel, reactor vessel internals, and RCS components:
 
Aging Management Review Results 3-218  ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Bolting Integrity Boric Acid Corrosion External Surfaces Monitoring Flow Accelerated Corrosion Flux Thimble Tube Inspection Lubricating Oil Analysis Nickel Alloy Aging Management Program Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors One-Time Inspection One-Time Inspection of ASME Code Class 1 Small-Bore Piping Periodic Inspection PWR Vessel Internals  Reactor Head Closure Studs Reactor Vessel Surveillance Steam Generator Tube Integrity Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)
TLAA  Water Chemistry LRA Tables 3.1.2-1 through 3.1.2
-4 summarize the results of AMRs for the RCS, reactor vessel, reactor vessel internal, and steam generator components and indicate AMRs claimed to be consistent with the GALL Report.
For component groups evaluated in the GALL Report for which the applicant had claimed consistency and for which the GALL Report does not recommend further evaluation, the staff performed an audit and review to determine whether the plant
-specific components in these GALL Report component groups were bounded by the GALL Report evaluation.
The applicant provided a note for each AMR line item describing how the information in the tables aligns with the information in the GALL Report. The staff reviewed those AMRs with Notes A through E, which indicate how the AMR was consistent with the GALL Report.
 
Aging Management Review Results 3-219 Note A indicates that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. The staff reviewed these line items to verify consistency with the GALL Report and the validity of the AMR for the site
-specific conditions.
Note B indicates that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff reviewed these line items to verify consistency with the GALL Report and that it had reviewed and accepted the identified exceptions to the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant was consistent with the AMP identified in the GALL Report and whether the AMR was valid for the site-specific conditions.
Note C indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the AMP identified by the GALL Report. This note indicates that the applicant was unable to find a listing of some system components in the GALL Report; however, the applicant identified a different component in the GALL Report that had the same material, environment, aging effect, and AMP as the component under review. The staff reviewed these line items to verify consistency with the GALL Report. The staff also determined whether the AMR line item of the different component applied to the component under review and whether the AMR was valid for the site
-specific conditions.
Note D indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff reviewed these line items to verify consistency with the GALL Report. The staff confirmed whether the AMR line item of the different component was applicable to the component under review and whether the exceptions to the GALL Report AMPs had been reviewed and accepted by the staff. The staff also determined whether the AMP identified by the applicant was consistent with the AMP identified in the GALL Report and whether the AMR was valid for the site
-specific conditions.
Note E indicates that the AMR line item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited. The staff reviewed these line items to verify consistency with the GALL Report and determined whether the identified AMP would manage the aging effect consistent with the AMP identified in the GALL Report and whether the AMR was valid for the site
-specific conditions.
The staff audited and reviewed the information in the LRA. The staff did not repeat its review of the matters described in the GALL Report; however, it did verify that the material presented in the LRA was applicable and that the applicant had identified the appropriate GALL Report AMRs. The staff's evaluation is discussed below.
The staff reviewed the LRA to confirm that the applicant:  (a) provided a brief description of the system, components, materials, and environments; (b) stated that the applicable aging effects were reviewed and evaluated in the GALL Report; and (c) identified those aging effects for the RCS, reactor vessel, reactor vessel internals, and steam generator components that are subject to an AMR.
Aging Management Review Results 3-220 On the basis of its audit and review, the staff determines that, for AMRs not requiring further evaluation, as identified in LRA Table 3.1.1, the applicant's references to the GALL Report are acceptable and no further staff review is required.
3.1.2.1.1  AMR Results Identified as Not Applicable LRA Table 3.1.1, items 3.1.1-38-51, discusses the applicant's determination on GALL Report AMR line items that are applicable only to BWR
-designed reactors. In the applicant AMR discussions for line items 38
-51, no additional information is provided. The staff confirmed that AMR line items 38
-51, in Table 1 of the GALL Report, Volume 1 are only applicable to BWR designed reactors, and that Salem is a PWR. Based on this determination, the staff finds that the applicant has provided an acceptable basis for concluding AMR line items 38
-51 in Table 1 of the GALL Report, Volume 1 are not applicable to Salem.
LRA Table 3.1.1, item 3.1.1
-53 addresses steel piping, piping components, and piping elements exposed to closed
-cycle cooling water subject to loss of material due to general, pitting, and crevice corrosion for this component group. The applicant stated that this line item is not applicable because it has no in
-scope steel piping, piping components, or piping elements exposed to closed
-cycle cooling water in the RCS, so the applicable GALL Report line item was not used. The staff reviewed the applicant's UFSAR and confirmed that no in
-scope steel piping, piping components, and piping elements exposed to closed
-cycle cooling water are present in these systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.1.1, item 3.1.1
-54 addresses copper alloy piping, piping components, and piping elements exposed to closed
-cycle cooling water subject to loss of material due to pitting, crevice, and galvanic corrosion for this component group. The applicant stated that this line item is not applicable because it has no in
-scope copper alloy piping, piping components, or piping elements exposed to closed
-cycle cooling water in the reactor vessel, internals, and RCS, so the applicable GALL Report line item was not used. The staff reviewed the applicant's UFSAR and confirmed that no in
-scope copper alloy piping, piping components, and piping elements exposed to closed-cycle cooling water are present in these systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.1.1, item 3.1.1
-56 addresses copper alloy greater than 15 percent Zn piping, piping components, and piping elements exposed to closed-cycle cooling water subject to loss of material due to selective leaching for this component group. The applicant stated that this line item is not applicable because it has no in
-scope copper alloy greater than 15 percent Zn components exposed to closed-cycle cooling water in the reactor vessel, internals, and RCS, so the applicable GALL Report line item was not used. The staff reviewed the applicant's UFSAR and confirmed that no in
-scope copper alloy greater than 15 percent Zn piping, piping components, and piping elements exposed to closed
-cycle cooling water are present in these systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.1.1, item 3.1.1
-66 addresses steel steam generator (SG) secondary manways and handholds, cover only exposed to air with leaking secondary
-side water and/or steam subject to loss of material due to erosion for this component group. The applicant stated that this line item is not applicable because these components are not exposed to air with leaking secondary
-side water and/or steam since there has been no operating experience at its plant with leaking manways or handholds.
 
Aging Management Review Results 3-221 The staff noted that even if the applicant had not observed any operating experience of leaking manways or handholes, this does not indicate that this Material, Environment, Aging Effect/Mechanism, and Aging Management Program (MEAP) combination can be excluded for these components during the period of extended operation. The staff determined that the applicant did not provide sufficient information to justify that LRA Table 3.1.1, item 3.1.1
-66 is not applicable.
By letter dated July 30, 2010, the staff issued RAI 3.1.1.66-01, requesting that the applicant demonstrate how the aging effect of loss of material due to erosion for steel SG secondary manways, cover only exposed to air with leaking secondary
-side water and/or steam will never occur during the period of extended operation, or revise accordingly its proposed LRA Table 3.1.1, item 3.1.1
-66. In its response dated August 26, 2010, the applicant stated that it agreed with the staff that the aging effect of loss of material due to erosion for steel SG secondary manways, cover only, exposed to air with leaking secondary side water and/or steam may occur during the period of extended operation. The applicant further stated that this  aging effect and mechanism also applies to the component type, Steam Generators (Inspection Ports and Diaphragm, Handholes and Covers) for the hand hole covers only since they are also constructed of steel and are potentially exposed to the environment of air with leaking secondary side water and/or steam. Consequently, the applicant revised LRA Table 3.1.1, item 3.1.1
-66, by identifying this item as consistent with the GALL Report and stated that ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program will be used to manage loss of material due to erosion for the steel SG secondary manway and handhole covers exposed to air with leaking secondary-side water and/or stea
: m. The applicant also indicated that LRA Table 3.1.1, item 3.1.1-66, pertains to the once
-through SGs (OTSGs), whereas its SGs are recirculating SGs(RSGs). The staff noted that this item appears only in GALL Revision 1 Volume 2 Table IV.D2 for OTSGs; however, the staff noted that it does not preclude the associated aging effect from being applicable to a component with a similar material/environment/aging effect and mechanism combination in RSGs.
The staff reviewed the applicant's response to RAI 3.1.1.6 6-01 and finds it not acceptable because the staff noted that in the revised LRA Table 3.1.2-4 SG inspection ports and diaphragm, handholes and covers are described as being fabricated as carbon or low alloy steel with stainless steel cladding, whereas in the text of its response, the applicant described this component as constructed of steel, at least for the covers.
In a conference call on September 9, 2010, to discuss and clarify the applicant's response, the applicant agreed to revise LRA Table 3.1.2-4 and change the material to low alloy steel, consistent with the text in response to RAI 3.1.1.66-01. In letter dated October 8, 2010, the applicant clarified that, although the component SG inspection ports and diaphragm, handholes and covers does not have the material "carbon or low alloy steel with stainless steel cladding", it contains both low alloy steel and stainless steel. The staff noted that in order to provide distinction between the materials, the applicant separated this component into two components: SG inspection ports, handholes and covers, and SG inspection port diaphragm. The applicant revised the material for the component SG inspection ports, handholes and covers from "carbon or low alloy steel with stainless steel cladding" to "low alloy steel", and included the component SG inspection port diaphragm constructed of stainless steel that only applies to the Unit 2 steam generators. The staff noted that as result of the revision described above, the applicant revised the aging effect of loss of Aging Management Review Results 3-222 material due to pitting and crevice corrosion with loss of material due to general, pitting and crevice corrosion. Consistent with the AMR items in GALL Report for steam generators the applicant revised LRA Table 3.1.2-4 to refer to GALL item IV.D1-12 instead of VIII.F
-23 for this component and stated that ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program will be used to manage the aging effect of loss of material due to general, pitting and crevice corrosion, in complement with the Water Chemistry Program. As a result of adding the aging effect of loss of material due to erosion for the SG inspection ports, handholes and covers and SG secondary manways and covers, consistent with other component types in LRA Table 3.1.2-4, the applicant revised the generic note "A" with a generic note "C"
. The applicant updated LRA Table 2.3.1-4 to reflect the separation between SG inspection ports, handholes and covers and Unit 2 SG inspection port diaphragm. The applicant revised LRA Table 3.1.1, item 3.1.1
-16,  and LRA Section 3.1.2.2.2.2 to include the SG low alloy steel inspection ports, handholes and covers exposed to treated water to be managed for loss of material due to general, pitting and crevice corrosion. It also revised LRA Table 3.1.2-4 to clarify that the SG stainless steel inspection port diaphragm is applicable to only Unit 2 SGs. The applicant revised LRA Table 3.4.1, item 3.4.1
-14 and LRA Section 3.4.2.2.6 to include the Unit 2 SG stainless steel inspection port diaphragm exposed to treated water to be managed for cracking due to SCC. The applicant also revised LRA Table 3.4.1, item 3.4.1
-16 and LRA Section 3.4.2.2.7.1 to include this component to be managed for loss of material due to pitting and crevice corrosion. In LRA Table 3.4.1, items 3.4.1
-14 and 3.4.1
-16, the applicant stated that components in the Steam Generators have been aligned to these item numbers based on material, environment, and aging effect, and that the Steam Generator Tube Integrity Program will be substituted to verify the effectiveness of the Water Chemistry Program, to manage cracking due to SCC and the loss of material due to pitting and crevice corrosion respectively in the Unit 2 SG stainless steel inspection port diaphragm exposed to treated water >140&deg; F. In addition, the applicant stated that since the stainless steel cladding is no longer valid for the SG inspection ports, handholes and covers, the corresponding aging effect of cracking due to stress corrosio n cracking of stainless steel in the environment of treated water > 140&deg; F is no longer applicable, and was deleted from LRA Table 3.1.2-4. Based on its review, the staff finds the applicant's response to RAI 3.1.1.66-01 acceptable because the applicant has revised LRA sections related to its steam generators in order to include the appropriate components for which it identified the adequate aging effects and aging management programs, and revised the plant specific notes. The staff's evaluation of the applicant's revisions to LRA Sections 3.1.2.2.2.2, 3.4.2.2.6 and 3.4.2.2.7.1, LRA Table 3.1.1, item 3.1.1
-16, and LRA Table 3.4.1, items 3.4.1
-14 and 3.4.1
-16, are documented in SER Sections 3.1.2.2.2.2, 3.4.2.2.6 and 3.4.2.2.7.1, respectively. The staff's concern described in RAI 3.1.1.66-01 is resolved.
The staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that their intended functions will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
LRA Table 3.1.1, item 3.1.1
-75 addresses nickel
-alloy once
-through steam generator tubes exposed to secondary feedwater/steam subject to denting due to corrosion of the carbon steel tube support plate for this component group. The applicant stated that this line item is not applicable because it does not have once
-through steam generators, so the applicable GALL Report line item was not used. The staff noted that item 3.1.1
-75 references GALL AMR item IV.D2-13, which is applicable to once
-through steam generators. The staff reviewed the applicant's UFSAR Section 5.1, Figures 5.1-3 and 5.1-3A and confirmed that the applicant's Aging Management Review Results 3-223 steam generators for both units are recirculating steam generators and, therefore, finds the applicant's determination acceptable.
LRA Table 3.1.1, item 3.1.1
-77 addresses nickel
-alloy steam generator tubes and sleeves exposed to phosphate chemistry in secondary feedwater/steam subject to loss of material due to wastage and pitting corrosion for this component group. The applicant stated that this line item is not applicable because the applicant does not use phosphate chemistry in secondary feedwater or steam, so the applicable GALL Report line item was not used. The staff reviewed UFSAR Section 10.3.5.2 and confirmed that the applicant does not operate on phosphate chemistry in the secondary side and, therefore, finds the applicant's determination acceptable.
LRA Table 3.1.1, item 3.1.1
-78 addresses steel steam generator tube support lattice bars exposed to secondary feedwater/steam subject to wall thinning due to flow
-accelerated corrosion for this component group. The applicant stated that this line item is not applicable because its steam generators do not contain lattice bars, so the applicable GALL Report line item was not used. The staff noted that in LRA Section 2.3.1.4, the applicant stated its Unit 1 uses Westinghouse Model F recirculating steam generators and Unit 2 uses AREVA 61/19T recirculating steam generators. The staff reviewed UFSAR Figures 5.1-3 and 5.1-3A for Units 2 and 1, respectively, and confirmed that the steam generators do not have lattice bars and, therefore, finds the applicant's determination acceptable. LRA Table 3.1.1, item 3.1.1
-79 addresses nickel
-alloy steam generator tubes exposed to secondary feedwater/steam subject to denting due to corrosion of the steel tube support plate.
The applicant stated that this line item is not applicable because its steam generators do not contain steel tube support plates, so the applicable GALL Report line item was not used. The staff reviewed the applicant's UFSAR and confirmed that the steam generators for Units 1 and 2 do not use steel tube support plates and, therefore, finds the applicant's determination acceptable.
LRA Table 3.1.1, item 3.1.1
-82 addresses the stainless steel steam generator primary
-side divider plate exposed to reactor coolant subject to cracking due to SCC for this component group. The applicant stated that this line item is not applicable because its steam generator primary-side divider plates are made of nickel alloy, so the applicable GALL Report line item was not used. The staff reviewed UFSAR Section 5.5.2.2.1 and confirmed that the divider plate for the steam generator is fabricated of nickel alloy. The staff noted that in LRA Table 3.1.1, item 3.1.1
-81, nickel
-alloy primary head divider plates are managed for cracking due to SCC. Based on its review as described above, the staff finds the applicant's determination acceptable.
LRA Table 3.1.1, item 3.1.1
-84, addresses nickel alloy steam generator components such as secondary side nozzles
- vent, drain, and instrumentation exposed to secondary feedwater and/or steam subject to cracking due to stress corrosion cracking (SCC) for this component group. The applicant stated that this line item is not applicable because this component, material, environment, and aging effect/mechanism combination does not apply since its plant does not have nickel alloy steam generator secondary side nozzles exposed to secondary feedwater and/or steam.
The staff noted that the applicant's description of its steam generators design in LRA Sections 2.3.1.4 and B.2.1.10, as well as in UFSAR rev. 24 did not provide sufficient information associated with the materials of the  steam generator secondary side nozzles to determine whether the aging effect of SCC is applicable for those components. Moreover, the staff noted Aging Management Review Results 3-224 that in LRA Table 3.1.2-4, the applicant included nickel alloy spray nozzles exposed to treated water, but did not address the aging effect of SCC.
By letter dated July 30, 2010, the staff issued RAI 3.1.1.84-01, requesting that the applicant clarify whether its steam generators contain any nickel alloy steam generator components exposed to secondary water and/or steam, or revise accordingly its proposed LRA Table 3.1.1, item 3.1.1
-84. The staff further requested that the applicant justify why cracking due to SCC is an aging effect that does not need to be addressed for the nickel alloy steam generator spray nozzles exposed to treated water.
In its response dated August 26, 2010, the applicant stated that it inadvertently omitted the aging effect and mechanism of cracking due to SCC for the nickel alloy spray nozzles, which are installed in Unit 1 steam generators. The applicant stated in LRA Table 3.1.2-4 the spray nozzles are the J-nozzles constructed of nickel alloy and are connected to each of the Unit 1 carbon steel steam generator feedwater rings. The applicant also explained that Unit 2 J-nozzles are constructed of stainless steel and are connected to each of the Unit 2 stainless steel feedwater rings which were added to LRA Table 3.1.2-4 as stated in response to RAI 3.1.2.2.14
-01, dated July 28, 2010. The applicant revised LRA Table 3.1.1, Item 3.1.1
-84 and LRA Table 3.1.2-4, by identifying this item as consistent with the GALL Report and stated the Water Chemistry Program and the One
-Time Inspection Program will be used to manage cracking due to SCC for the Unit 1 nickel alloy SG spray nozzles exposed to secondary feedwater and/or steam, consistent with GALL AMR item IV.D2
-9. The applicant also revised LRA Table 3.1.2-4 to include the aging effects of cracking due to SCC, and loss of material due to pitting and crevice corrosion for the added Unit 2 stainless steel spray nozzles. In the revise d LRA Table 3.1.2-4, the applicant stated that these aging effects are managed with the Water Chemistry Program and the One
-Time Inspection Program, by selecting GALL Report items VIII.F-23 and VIII.F
-24. The applicant also indicated that LRA Table 3.1.1, item 3.1.1
-84, pertains to the once
-through SGs (OTSGs), whereas its SGs are recirculating SGs (RSGs). The staff noted that this item appears only in GALL Revision 1 Volume 2 Table IV.D2 for OTSGs; however, the staff noted that it does not preclude the associated aging effect from being applicable to a component with a similar material/environment/aging effect and mechanism combination in RSGs.
The staff reviewed the applicant's response to RAI 3.1.1.84-01 and finds it not acceptable because it was not clear to the staff whether the applicant considered the SG spray nozzles as piping nozzles that are addressed by GALL AMR items for piping elements, or as J
-nozzles that should be considered as SG secondary internals, and therefore are managed by the Steam Generator Tube Integrity Program.
The staff was also not clear whether the generic note A was appropriate, since the applicant selected AMPs not directly applicable to these components.
In a conference call on September 9, 2010, to discuss and clarify the applicant's response, the applicant agreed to revise LRA Table 3.1.2-4 according to the staff's concerns.
In letter dated October 8, 2010, the applicant revised LRA Table 3.1.2-4 to replace the One-Time Inspection Program with the Steam Generator Tube Integrity Program to manage loss of material due to pitting and crevice corrosion, and cracking due to SCC for the Unit 1 SG spray nozzles, the Unit 2 SG spray nozzles and SG feedwater ring. The applicant also revised the GALL item from IV.D2
-9 to IV.D1
-14 in LRA Table 3.1.2-4, and the associated Table 3.1.1 item from 3.1.1
-84 to 3.1.1
-74, since the Unit 1 nickel alloy SG spray nozzles are considered an internal nozzle. In addition, the applicant provided additional line items to LRA Tab le 3.1.2-4 for  the following component types: Unit 1 nickel alloy SG spray nozzles, Unit 2 stainless steel SG Aging Management Review Results 3-225 spray nozzles, Unit 1 carbon steel SG feedwater ring, and Unit 2 SG stainless steel feedwater ring exposed to the treated water and treated water > 140&deg; F since these environments affected both the internal and external surfaces of these components. The applicant stated that the Steam Generator Tube Integrity Program will be used to manage the applicable aging effects for the internal and external surfaces of these components, in complement with the Water Chemistry Program, and revised accordingly Plant Specific Note 2. The applicant also revised LRA Table 2.3.1-4 to reflect the separation between SG feedwater rings and supports, Unit 1 and Unit 2 SG spray nozzles, and Unit 1 and Unit 2 SG feedwater rings. The applicant updated LRA Table 3.1.1, item 3.1.1
-74, to include the Unit 1 nickel alloy SG spray nozzles in the list of components managed with this item for cracking due to SCC and loss of material due to crevice corrosion and fretting. The applicant revised LRA Table 3.1.1, item 3.1.1
-84, to state that this item is not applicable because the installed SGs do not have attached nozzles constructed of nickel alloy exposed to secondary feedwater/steam, and the Unit 1 nickel alloy SG spray nozzles are considered Steam Generator internal components and are evaluated under Item 3.1.1-74. The applicant revised LRA Table 3.4.1, item 3.4.1
-14 and LRA Section 3.4.2.2.6 to include the Unit 2 stainless steel SG feedwater ring, and spray nozzles exposed to treated water > 140&deg; F to be managed for cracking due to SCC. The applicant also revised LRA Table 3.4.1, item 3.4.1
-16 and LRA Section 3.4.2.2.7.1 to include Unit 2 stainless steel SG feedwater ring and supports, and spray nozzles exposed to treated water to be managed for loss of material due to pitting and crevice corrosion. In LRA Table 3.4.1, items 3.4.1
-14 and 3.4.1
-16, the applicant stated that components in the Steam Generators system have been aligned to these item numbers based on material, environment, and aging effect, and that the Steam Generator Tube Integrity Program will be substituted to verify the effectiveness of the Water Chemistry Program, to manage cracking due to SCC and the loss of material due to pitting and crevice corrosion respectively in the Unit 2 stainless steel SG feedwater ring, and spray nozzles exposed to treated water >140&deg; F or treated water for this syste
: m. Based on its review, the staff finds the applicant's response to RAI 3.1.1.84-01 accepTable because the applicant has revised LRA sections related to its steam generators in order to include the appropriate components for which it identified the adequate aging effects and aging management programs, and revised the plant specific notes. The staff's evaluation of the applicant's revisions to LRA table 3.1.2-4, LRA Sections 3.1.2.2.2.2, 3.4.2.2.6 and 3.4.2.2.7.1, LRA Table 3.1.1, item 3.1.1
-16, and LRA Tab le 3.4.1, items 3.4.1
-14 and 3.4.1
-16, are documented in SER Sections 3.1.2.3.4, 3.1.2.2.2.2, 3.4.2.2.6 and 3.4.2.2.7.1, respectively. The staff's concern described in RAI 3.1.1.84-01 is resolved.
During the August 2010 NRC Region I License Renewal inspection, a discrepancy between LRA Table 3.1.2-4 and the Steam Generator Tube Integrity Program basis document was noted. The staff noted that SG moisture separators
- vanes and dryers, and Unit 1 SG secondary flow distribution baffle were contained in the program basis document, but did not appear in the LRA. The staff also noted that the SG loose part monitoring (i.e., trapping) system of Unit 2 SGs only was not included in the LRA for aging management. The staff noted that a degradation of these SG secondary side internals could affect the integrity of SG tubes and questioned the applicant about these discrepancies and whether it needed to manage the aging effects for those components.
In its response dated August 26, 2010, the applicant explained that it removed SG moisture separators
- vanes and dryers and Unit 1 SG secondary flow distribution baffle from the LRA since they were determined to not have an intended function. The applicant stated that upon further review it has been concluded that the intended function of structural support will be applied to these SG secondary internal components. The applicant further stated that for both Aging Management Review Results 3-226 units, the vanes and dryers are constructed of carbon steel, and that the Unit 1 SGs contain the secondary flow distribution baffle, which is constructed of stainless steel. The applicant further stated that the SG loose part monitoring system on Unit 2 only is constructed of stainless steel, and considered as a secondary internal component, and also has the intended function of structural support. The appcliant revised LRA Table 2.3.1-4 to add a new component, SG secondary internals, and its intended function of structural support. The applicant revised LRA Table 3.1.2-4 to provide AMR line items for this added component of SG secondary internals fabricated from carbon steel or stainless steel and exposed to treated water (external) and treated water
> 140&deg; F, with the following aging effects: loss of material due to general, pitting and crevice corrosion; wall thinning due to flow accelerated corrosion; loss of material due to pitting and crevice corrosion and cracking due to SCC. The applicant revised LRA Table 3.1.1, item 3.1.1
-16 and LRA Section 3.1.2.2.2.2 to include the steel SG secondary internals exposed to secondary feedwater and steam to include these component s to be managed for loss of material due to general, pitting and crevice corrosion.
The staff reviewed the applicant's response and finds it not acceptable because the staff was not clear whether a separate intended function of direct flow would be appropriate for some SG secondary internals, such as the flow distribution baffle, and whether the generic note A was appropriate. The staff also noted that the applicant selected the One-Time Inspection Program to manage the aging effect of loss of material due to pitting and crevice corrosion, in complement with the Water Chemistry Program. However, the staff noted that this aging effect for the SG secondary internals should be managed with the Steam Generator Tube Integrity Program in order to assess any degradation of the secondary side SG components that could affect the integrity of the SG tube bundles.
In a conference call on September 9, 2010, to discuss and clarify the applicant's response, the applicant did not agree with the need to include a new intended function, and agreed to revise LRA Table 3.1.2-4 according to the staff's other concerns.
In letter dated October 8, 2010, the applicant stated that it replaced the One
-Time Inspection Program with the Steam Generator Tube Integrity Program to manage the aging effect loss of material due to pitting and crevice corrosion for the stainless steel SG secondary internals exposed to treated water, and revised the plant specific note from "C" to "E, 3" associated with the Steam Generator Tube Integrity Program and from "A" to "C" associated with the Water Chemistry program for these components. The applicant revised LRA Table 3.4.1, item 3.4.1-16 and LRA Section 3.4.2.2.7.1 to include these component s to be managed for loss of material due to pitting and crevice corrosion. In addition, for the SG tubesheets, the applicant revised LRA Table 3.1.1, item 3.1.1
-16, by substituting the Steam Generator Tube Integrity Program to verify the effectiveness of the Water Chemistry Program, instead of the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program, to manage the loss of material due to general, pitting and crevice corrosion in the steel tubesheets and updated LRA Section 3.1.2.2.2.2 accordingly. The applicant also corrected the plant specific note "E, 4" to "E, 3" when the Steam Generator Tube Integrity Program is substituted to manage the aging effect(s) applicable to this component type, material, and environment combination.
Based on its review, the staff finds the applicant's response to the demand of clarification acceptable because the applicant has revised LRA sections related to its steam generators in order to include the appropriate components for which it identified the adequate aging effects and aging management programs, and revised the plant specific notes. The staff's evaluation of the applicant's revisions to LRA Table 3.1.2-4 and LRA Sections 3.1.2.2.2.2, and 3.4.2.2.7.1, LRA Table 3.1.1, item 3.1.
1-16, and LRA Table 3.4.1, item 3.4.1
-16, are documented in SER Aging Management Review Results 3-227 Sections 3.1.2.2.2.2 and 3.4.2.2.7.1, respectively. The staff's concern described in its demand of clarification is resolved.
The staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that their intended functions will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
LRA Table 3.1.1, item 3.1.1
-87 addresses steel piping, piping components, and piping elements in concrete. The GALL Report states that there is not an AERM. The applicant stated that this line item is not applicable because its reactor vessel, internals, and RCS have no in
-scope steel piping, piping components, or piping elements embedded in concrete, so the applicable GALL Report line item was not used. The staff reviewed the applicant's UFSAR and confirmed that no in-scope steel piping, piping components, and piping elements in concrete are present in these systems and, therefore, finds the applicant's determination acceptable.
3.1.2.1.2  Loss of Preload Due to Self
-Loosening LRA Table 3.1.1, item 3.1.1
-52 addresses stainless, carbon, and low
-alloy steel closure bolting exposed externally to indoor uncontrolled air or outdoor air, which are being managed for loss of preload due to self
-loosening. The LRA credits the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program to manage the aging effect. The GALL Report recommends GALL AMP XI.M18, "Bolting Integrity," to ensure that these aging effects are adequately managed. The associated AMR line items cite generic note E. For those line items associated with generic note E, GALL AMP XI.M18 recommends using visual inspections and industry guidance on proper selection of bolting materials, lubricants, and torque to manage the aging of these line items. In its review of components associated with item 3.1.1
-52 for which the applicant cited generic note E, the staff noted that the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program proposes to manage the aging of stainless steel, carbon, and low
-alloy steel bolting through the use of visual inspections and industry guidance on bolting materials, lubricants, and torque.
The staff's evaluation of the applicant's Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program is documented in SER Section 3.0.3.2.4. In its review of components associated with item 3.1.1
-52, the staff finds the applicant's proposal to manage aging using the Inspection of the Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program acceptable because:  (1) its visual inspections are effective methods for detecting the applicable aging effects; (2) incorporation of industry guidance on proper selection of bolting materials, lubricants, and torque are effective methods for preventing loss of preload; (3) the frequency of monitoring is adequate to prevent significant degradation; and (4) the inspection methods are consistent with the GALL Report recommended AMP.
The staff concludes that 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).
 
Aging Management Review Results 3-228 3.1.2.1.3  Loss of Fracture Toughness Due to Thermal Aging Embrittlement LRA Table 3.1.1, item 3.1.1
-55 addresses loss of fracture toughness due to thermal aging embrittlement of CASS Clas s 1 pump casings and valve bodies and bonnets exposed to reactor coolant greater than 250
&deg; C (482&deg; F). LRA item 3.1.1-55 also indicates that the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program is credited to manage the aging effect and ASME Code Case N
-481 provides an alternative for the aging management. LRA Table 3.1.2-1 indicates that the component under LRA item 3.1.1-55 is the casings of the RCPs and the aging effect is managed by the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program and TLAA (LRA Section 4.4.4). LRA Table 3.1.2-1 further addresses two AMR line items to manage the loss of fracture toughness of the CASS Class 1 pump casings. In the LRA table, LRA Note A is claimed for the line item that credits the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. The LRA indicates that LRA Note A means that the item is consistent with the GALL Report item for component, material, environment, aging effect, and AMP. In addition, LRA Table 3.1.2-1 claims LRA Note E for the CASS Class 1 pump casing line item that credits a TLAA. The LRA indicates that LRA Note E means that the item is consistent with the GALL Report item for component, material, environment, and aging effect, but a different AMP is credited or the GALL Report identified a plant
-specific AMP. The applicant further stated, using LRA Note 4, that ASME Code Case N-481 is applicable to Salem, therefore, its aging management will be evaluated as a TLAA. LRA Section 4.4.4 also indicates that the code case allows the replacement of ASME Code Section XI volumetric examinations of primary loop pump casings with fracture
-mechanics-based integrity evaluations (Item (d) of the code case) supplemented by specific visual examinations (Items (a), (b), and (c) of the code case). In LRA Section 4.4.4, the applicant indicated that the applicant's TLAA is associated with Item (d) of the code case.
The staff reviewed the AMR line items against GALL Report, Volume 1, Table 1, ID 55 and Volume 2, item IV.C2
-6. The staff noted that the GALL Report, Volume 2, under item IV.C2
-6, recommends GALL AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," to manage the aging effect. The GALL Report further indicates that for pump casings and valve bodies, screening for susceptibility to thermal aging is not necessary. The staff also noted that the GALL Report indicates that the ASME Code Section XI inspection requirements are sufficient for managing the aging effect and, alternatively, the requirements of ASME Code Case N
-481 for pump casings are sufficient for managing the aging effect. Therefore, the staff finds that the applicant's aging management method, which uses the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program with the alternative requirements of ASME Code Case N
-481, is consistent with the GALL Report.
The staff's evaluations of the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program and the applicability of ASME Code Case N
-481, including the TLAA, are documented in SER Sections 3.0.3.1.1 and 4.4.4.2, respectively. In its review, the staff finds that the use of the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program and ASME Code Case N
-481, including the TLAA, is acceptable to manage the loss of fracture toughness of the CASS Class 1 pump casings because:  (1) the applicant's proposed aging management method and programs are consistent with the GALL Report; and (2) as required by ASME Code Case N-481, the applicant's plant
-specific analysis demonstrates the safety and serviceability of the pump casings and the applicant's TLAA results demonstrate that the stability of the postulated flaws remains valid during the period of the extended operation.
 
Aging Management Review Results 3-229 The staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.1.2.1.4  Loss of Fracture Toughness due to Thermal Aging and Neutron Irradiation Embrittlement LRA Table 3.1.1, item 3.1.1
-80 addresses loss of fracture toughness due to thermal aging and neutron irradiation embrittlement of CASS reactor vessel internals exposed to reactor coolant and neutron flux. LRA item 3.1.1
-80 also indicates that the PWR Vessel Internals Program will be substituted to manage the aging effect in CASS reactor vessel internal components exposed to reactor coolant and neutron flux. In addition, LRA Section B.2.0 indicates that GALL AMP XI.M13, "Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS)," is not used for the applicant's aging management.
LRA Table 3.1.2-3 further addresses one AMR line item to manage the loss of fracture toughness due to thermal aging and neutron irradiation embrittlement of the CASS incore guide cruciforms exposed to reactor coolant and neutron flux. The applicant claimed LRA Note E for the LRA line item and the LRA indicates that LRA Note E means that the item is consistent with the GALL Report item for component, material, environment, and aging effect, but a different AMP is credited or the GALL Report identified a plan t-specific AMP. The staff noted that LRA Note E is claimed because the applicant credited the PWR Vessel Internals Program in conjunction with the UFSAR supplement commitment (LRA Section A.2.1.7) rather than GALL AMP XI.M13, "Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS)," that is recommended by the GALL Report.
The staff reviewed the AMR line item in comparison with GALL Report, Volume 1, Table 1, ID 80 and Volume 2, items IV.B2
-21 and IV.B2
-37. The staff noted that the GALL Report, under items IV.B2 21 and IV.B2
-37, recommends GALL AMP XI.M13, "Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS),"  to manage the loss of fracture toughness due to thermal aging and neutron irradiation for the lower internals and upper internals of the Westinghouse PWR vessels, respectively.
In its review, the staff noted that LRA Table 3.1.2-3 does not address loss of fracture toughness due to thermal aging and neutron irradiation embrittlement for rod cluster control assembly (RCCA)  guide tube assemblies (lower flanges), upper internals assembly (upper support column bases), and upper internals assembly (static flow mixers) although the LRA indicates that the material of the components is CASS and the PWR Vessel Internals Program is credited to manage the changes in dimensions due to void swelling and cracking due to SCC and IASCC. The staff also noted that the aging effects addressed in the LRA table indicate that neutron irradiation is applicable to the components because the void swelling and IASCC require the exposure of the components to neutron irradiation. In addition, the staff noted that the omission of the components in managing loss of fracture toughness for the CASS reactor vessel internals is not consistent with GALL Report, Volume 1, Table 1, ID 80 that addresses loss of fracture toughness due to thermal aging and neutron irradiation embrittlement for CASS reactor vessel internals including upper internals assembly, lower internal assemblies, and control rod guide tube assembly.
By letter dated June 11, 2010, the staff issued RAI 3.1.2.1-01 requesting that the applicant describe what program is used to manage loss of fracture toughness due to thermal aging and Aging Management Review Results 3-230 neutron irradiation embrittlement for RCCA guide tube assemblies (lower flanges), upper internals assembly (upper support column bases), and upper internals assembly (static flow mixers) that are described in LRA Table 3.1.2-3. The staff also requested that, if the applicant does not manage loss of fracture toughness for the CASS components, the applicant justify why it is not required to manage loss of fracture toughness for the components.
In its response to the RAI, dated July 8, 2010, the applicant indicated that the RCCA guide tube assemblies (lower flanges), the upper internals assembly (static flow mixers), and the upper internals assembly (upper support column bases) components were inadvertently omitted from the AMR to manage loss of fracture toughness. The applicant also indicated that these components are within the reactor vessel internals and are exposed to reactor coolant and neutron flux and have an aging effect of loss of fracture toughness due to thermal aging and neutron irradiation embrittlement. The applicant further indicated that the applicant credits the PWR Vessel Internals Program to manage the aging effect for the components and that LRA Table 3.1.2-3 is revised to add these component types for adequate aging management of loss of fracture toughness.
Based on its review, the staff finds the applicant's response to RAI 3.1.2.1-01 acceptable because the addition of the aforementioned AMR line items is consistent with the GALL Report and the applicant clarified that the PWR Vessel Internals Program is credited to manage loss of fracture toughness for the components. The staff's concern described in RAI 3.1.2.1-01 is resolved. The staff's evaluation of the PWR Vessel Internals Program is documented in SER Section 3.0.3.3.1. In its review, the staff finds the proposed PWR Vessel Internals Program acceptable to manage the loss of fracture toughness for the CASS reactor vessel internals because:  (1) the applicant's commitment to participate in the industry programs for investigating and managing aging effects on reactor internals ensures that adequate inspections and/or preventive measures are identified to manage the loss of fracture toughness for the CASS reactor vessel internal components, (2) the applicant's commitment to evaluate and implement the results of the industry programs as applicable to the reactor vessel internals can ensure that the aging management lessons and recommendations identified from the industry experience and programs are adequately implemented to the applicant's AMP, and (3) the applicant's commitment to submit an inspection plan for reactor internals to the NRC for review, upon completion of these programs, but not less than 24 months before the entering the period of the extended operation, can ensure the timely identification and adequate management of the effects of aging.
The staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by
 
10 CFR 54.21(a)(3).
3.1.2.1.5  Cracking Due to Primary Water Stress
-Corrosion Cracking LRA Table 3.1-1, item 3.1.1
-81 addresses cracking due to PWSCC for the nickel alloy or nickel-alloy clad steam generator divider plate exposed to reactor coolant. The applicant credited its Water Chemistry Program to manage cracking due to PWSCC in the nickel
-alloy steam generator primary channel head divider plate exposed to reactor coolant in the steam generators
 
Aging Management Review Results 3-231 SRP-LR Section 3.1.2.2.13 identifies that cracking due to PWSCC could occur in 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. GALL AMR item IV.D1
-06 recommends GALL AMP XI.M2, "Water Chemistry," for PWR primary water for managing the aging effect of cracking in the nickel
-alloy steam generator divider plate exposed to reactor coolant.
UFSAR Section 5.5.2.2.1 states that the divider plate is fabricated with Inconel 690 for the Unit 2 replacement steam generators. The staff noted that the use of this Alloy 690 should prevent the aging effect of PWSCC. However, the applicant did not provide information related to the material of construction for the divider plate in the Unit 1 steam generators.
The staff noted that, from foreign operating experience in steam generators with a similar design to that of the applicant, extensive cracking due to PWSCC has been identified in steam generator divider plates made with Alloy 600, even with proper primary water chemistry. The staff noted that specifically, cracks have been detected in the stub runner, very close to the tubesheet/stub runner weld and with depths of almost a fourth of the divider plate thickness. Therefore, the staff noted that the applicant's Water Chemistry Program alone may not be effective in managing the aging effect of cracking due to PWSCC in the steam generator divider plate. The staff noted that although these steam generator divider plate cracks may not have a significant safety impact in themselves, these cracks could impact adjacent items, such as the tubesheet and the channel head, if they propagate to the boundary with these components. The staff further noted that for the tubesheet, PWSCC cracks in the divider plate could propagate to the tubesheet cladding with possible consequences to the integrity of the tube/tubesheet welds. Furthermore, the staff noted for the channel head, the PWSCC cracks in the divider plate could propagate to the steam generator triple point and potentially affect the pressure boundary of the steam generator channel head.
By letter dated June 10, 2010, the staff issued RAI 3.1.1-01, which request ed that the applicant discuss the materials of construction of the applicant's Unit 1 steam generator divider plate assembly; furthermore, if these materials are susceptible to cracking (e.g., Alloy 600 or the associated Alloy 600 weld materials), the staff requested the applicant to discuss the potential that cracking in the divider plate might propagate into other components (e.g., tubesheet cladding). The staff further requested that if propagation into these other components cannot be ruled out, the applicant should describe an inspection program (examination technique and frequency) for ensuring that there are no cracks propagating into other components (e.g., tubesheet and/or channel head) that could challenge the integrity of other adjacent components.
In its response to the RAI dated July 8, 2010, the applicant described the materials of its SG divider plate assemblies, which are nickel Alloy 600 for the stub runner and the divider plate components, and Alloy 82/182 for the welds that attach the divider plate and stub runner to each other, and to the channel head and to the tubesheet. The applicant also provided additional elements in order to justify why the potential for cracking of Unit 1 Model F SG divider plate propagating into adjoining components and resulting in loss of the integrity of the reactor coolant pressure boundary would not be expected to occur, and therefore, why the SG divider plate assemblies do not require an aging management program consisting of inspections for crack propagation.
 
Aging Management Review Results 3-232 Based on its review of the applicant's response, the staff noted that the applicant's response provided only qualitative arguments for concluding that divider plate crack growth is not a concern. The staff considered that this response did not provide a reasonable and sufficient basis for justifying the applicant's conclusions. Further, the staff noted that the use of analytical tools to predict the behavior of service
-induced cracking (in other components) has not always bounded actual service performance of these cracks. In addition, the staff noted that the likely presence of cracks in Alloy 600 steam generator divider plate assemblies may result in a condition where these cracks could propagate into surrounding pressure boundary areas, such as the tube
-to-tubesheet welds and the channel head.
Therefore, by letter dated September 29, 2010, the staff issued follow
-up RAI 3.1.1-02 requesting that the applicant provide an AMP, changes to an existing AMP, or a commitment to inspection(s) that would demonstrate the condition of the steam generator divider plate assemblies to support a conclusion that there will be no adverse consequences of divider plate assembly degradation during the renewed license perio
: d. In its response to the RAI dated October 7, 2010, the applicant described industry plans to study the potential for divider plate crack growth and develop an industry
-applied resolution to the concern through the EPRI Steam Generator Management Program (SGMP) Engineering and Regulatory Technical Advisory Group, which is expected to be completed by 2013. The applicant also described VT
-3 inspection performed on each of the four Unit 1 steam generator divider plates during a 2004 outage, and Visual Examination (VE) performed in the spring outage of 2010 on the Alloy 600 bottom bowl drain; the applicant stated that these examinations identifed no indications of degradation, although the staff concludes that these examinations would not be capable of detecting PWSCC cracking in these components. The applicant committed to perform an inspection of each of the four Unit 1 steam generators to assess the condition of the divider plate assembly. The applicant also stated that the examination technique(s) used will be capable of detecting PWSCC in the steam generator divider plate assemblies and the associated welds. Moreover, the applicant stated that steam generator divider plate inspections will be completed within the first ten years of the period of extended operation, i.e., prior to August 2026. In addition, the applicant stated that it also plans to remain involved with the on
-going industry studies related to divider plate cracking to ensure that any inspection requirements or other resolution actions promulgated to the industry are evaluated and implemented, as appropriate. Finally, the applicant stated that Commitment No. 50, covering the above inspection of each of Unit 1 steam generators to assess the condition of the divider plate assembly, will be added to Table A.5 License Renewal Commitment list.
Based on its review, the staff finds the applicant's response to RAI 3.1.1-02 and associated Commitment No. 50 acceptable because the applicant will assess the condition of the divider plate assembly in each of Unit 1steam generators by inspection during the period of extended operation, in a time period consistent with the detection of potential PWSCC cracks, and with appropriate examination techniques. The staff also notes that the applicant will remain involved with on-going industry efforts related to the divider plate cracking issue. The staff's concern described in RAIs 3.1.1-01 and 3.1.1
-02 is resolved.
In a conference call on September 16, 2010, the applicant confirmed that all the materials constituting the divider plate assemblies for Unit 2 steam generators are Alloy 690 and/or Alloy 52/152. As mentioned above, the staff considered that the use of these alloys should prevent the aging effect of PWSCC for the SG divider plate assemblies.
 
Aging Management Review Results 3-233 The staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that their intended functions will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.1.2.1.6  Conclusion for AMRs Consistent with the GALL Report The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing the associated aging effects. On the basis of its review, the staff concludes that the AMR results, which the applicant claimed to be consistent with the GALL Report, are consistent with the GALL Report AMRs. Therefore, the staff concludes that the applicant has demonstrated that the aging effects for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.1.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended LRA Section 3.1.2.2 provides further evaluation of aging management as recommended by the GALL Report for the RCS components. The applicant provided information concerning how it will manage the following aging effects:
cumulative fatigue damage loss of material due to general, pitting, and crevice corrosion loss of fracture toughness due to neutron irradiation embrittlement cracking due to 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 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 QA for aging management of nonsafety
-related components 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.
 
Aging Management Review Results 3-234 3.1.2.2.1  Cumulative Fatigue Damage LRA Section 3.1.2.2.1 states fatigue is a TLAA as defined in 10 CFR 54.3. Furthermore, TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c)(1). The applicant stated the evaluation of metal fatigue as a TLAA for the RCS, reactor vessel, reactor vessel internals, and steam generators are discussed in LRA Section 4.3. The applicant identified that the following AMRs in LRA Table 3.1.1 are applicable to this further evaluation item and that the analysis of metal fatigue for component addressed in these AMRs is a TLAA:
Item 3.1.1 The applicant stated that some of the Salem reactor vessel internal components designed to ASME Code Section III, SubSection NG requirements were required to be analyzed in accordance with applicable ASME Code Section III CUF calculation criteria. In LRA Table 3.1.2-3, the applicant identified that the reactor vessel internal lower internal assembly components were required to be analyzed in accordance with an applicable CUF analysis. The applicant stated that LRA Section 4.3 describes the evaluation of these TLAAs.
Item 3.1.1 The applicant stated that the Salem nickel
-alloy tubes and sleeves in a reactor coolant and secondary feedwater or steam environment were required to be analyzed in accordance with applicable ASME Code Section III CUF calculation criteria. In LRA Table 3.1.2-4, the applicant identified steam generator tube plugs and tubes required to be analyzed for CUF analyses and that these TLAAs are discussed and evaluated in LRA Section 4.3. Item 3.1.1 The applicant stated that the Salem 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 required to be analyzed in accordance with applicable ASME Code Section III CUF calculation criteria. In LRA Tables 3.1.2-1, 3.1.2-2, 3.1.2-4, 3.2.2-3, 3.3.2-2, 3.3.2-22, and 3.4.2
-2, the applicant identified bolting, piping, fittings, branch connections, valves, nozzles, and steam generator components that are required to be analyzed for CUF analyses and that these TLAAs are discussed and evaluated in LRA Section 4.3. Item 3.1.1 The applicant stated that the Salem steel, stainless steel, and nickel
-alloy RCPB piping, piping components, piping elements, flanges, nozzles, safe ends, pressurizer vessel shell heads and welds, heater sheaths and sleeves, penetrations, and thermal sleeves were required to be analyzed in accordance with applicable ASME Code Section III CUF calculation criteria. In LRA Tables 3.1.2-1, 3.1.2-2, 3.2.2-3, and 3.3.2-2, the applicant identified pressurizer components, pump casings, piping, thermowells, valve bodies, restricting orifices, fittings, and branch connections that are required to be analyzed for CUF analyses and that these TLAAs are discussed and evaluated in LRA Section 4.3. Item 3.1.1 The applicant stated that the Salem steel, stainless steel, nickel
-alloy, and nickel-alloy or stainless steel cladding reactor vessel components, flanges, nozzles, penetrations, pressure housings, safe ends, thermal sleeves, vessel shells, heads, and welds were required to be analyzed in accordance with applicable ASME Code Section III CUF calculation criteria. In LRA Table 3.1.2-2, the applicant identified control Aging Management Review Results 3-235 rod assemblies, nozzles, and reactor vessel components that are required to be analyzed for CUF analyses and that these TLAAs are discussed and evaluated in LRA Section 4.3. Item 3.1.1 The applicant stated that the Salem steel, stainless steel, nickel
-alloy, and steel with nickel
-alloy or stainless steel cladding steam generator components were required to be analyzed in accordance with applicable ASME Code Section III CUF calculation criteria. In LRA Table 3.1.2-4, the applicant identified steam generator components that are required to be analyzed for CUF analyses and that these TLAAs are discussed and evaluated in LRA Section 4.3. The staff reviewed LRA Section 3.1.2.2.1 against the general criteria in SRP
-LR Section 3.1.2.1 for performing AMR reviews, as subject to the additional further evaluation criteria in SRP
-LR Section 3.1.2.2.1, which states that fatigue is a TLAA as defined in 10 CFR 54.3 and that 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 the staff's recommended acceptance criteria and review procedures for reviewing these type of TLAAs in SRP
-LR Section 4.3, "Metal Fatigue Analysis."  The staff also reviewed LRA Section 3.1.2.2.1 and the AMRs discussed in this Section against the AMR items for evaluating PWR design cumulative fatigue damage, as given in AMR items 5
-10 of Table 1 of the GALL Report, Volume 1, Revision 1, and the AMR items derived from these GALL Report, Volume 1 AMR items. With regard to LRA Table 3.1.1, items 3.1.1-1 through 3.1.1
-4, the staff noted that these items are associated with BWR design plants and, therefore, not applicable to the applicant. With regard to LRA Table 3.1.1, item 3.1.1
-5, the staff noted that GALL AMR item IV.B2
-31 identifies cumulative fatigue damage as an applicable aging effect for reactor vessel internal components and recommends that the TLAA on metal fatigue be used to manage this aging effect. The applicant included applicable line items in LRA Table 3.1.2-3 for reactor vessel internal components that received ASME Code Section III CUF analysis calculations consistent with the recommendations in the SRP
-LR. Based on its review, the staff finds the applicant's AMR analysis on cumulative fatigue damage of reactor vessel internals acceptable because it is consistent with the recommendations in SRP
-LR Section 3.1.2.2.1. The staff evaluates the TLAA analysis for the reactor vessel internals components in SER Section 4.3.5. With regard to LRA Table 3.1.1, item 3.1.1
-6, the staff noted that GALL AMR item IV.D1
-21 identifies cumulative fatigue damage as an applicable aging effect for steam generator tubes and sleeves and recommends that the TLAA on metal fatigue be used to manage this aging effect. The applicant included applicable line items in LRA Table 3.1.2-4 for steam generator tubes and sleeves that received ASME Code Section III CUF analysis calculations consistent with the recommendations in the SRP
-LR. Based on its review, the staff finds the applicant's AMR analysis on cumulative fatigue damage of steam generator tubes and sleeves acceptable because it is consistent with the recommendations in SRP
-LR Section 3.1.2.2.1. The staff evaluates the TLAA analysis for the steam generator tubes and sleeves components in SER Section 4.3.1. With regard to LRA Table 3.1.1, item 3.1.1
-7, the staff noted that GALL AMR items IV.A2
-4, IV.C2-10, IV.C2-23, and IV.D1
-11 identify that cumulative fatigue damage is an applicable aging effect for 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 and recommends that the TLAA on metal fatigue be used to manage this aging effect. The applicant included applicable line items in LRA Aging Management Review Results 3-236 Tables 3.1.2-1, 3.1.2-2, 3.1.2-4, 3.2.2-3, 3.3.2-2, 3.3.2-22, and 3.4.2
-2 for bolting, piping, fittings, branch connections, valves, nozzles, and steam generator components that received ASME Code Section III CUF analysis calculations consistent with the recommendations in the SRP
-LR. Based on its review, the staff finds the applicant's AMR analysis on cumulative fatigue damage of bolting, piping, fittings, branch connections, valves, nozzles, and steam generator components acceptable because it is consistent with the recommendations in SRP
-LR Section 3.1.2.2.1. The staff evaluates the TLAA analysis for the bolting, piping, fittings, branch connections, valves, nozzles, and steam generator components in SER Sections 4.3.1 and 4.3.3. With regard to LRA Table 3.1.1, item 3.1.1
-8, the staff noted that GALL AMR item IV.C2
-25 identifies cumulative fatigue damage as an applicable aging effect for 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 and recommends that the TLAA on metal fatigue be used to manage this aging effect. The applicant included applicable line items in LRA Tables 3.1.2-1, 3.1.2-2, 3.2.2-3, and 3.3.2-2 for pressurizer components, pump casings, piping, thermowells, valve bodies, restricting orifices, fittings, and branch connections that received ASME Code Section III CUF analysis calculations consistent with the recommendations in the SRP
-LR. Based on its review, the staff finds the applicant's AMR analysis on cumulative fatigue damage of pressurizer components, pump casings, piping, thermowells, valve bodies, restricting orifices, fittings, and branch connections acceptable because it is consistent with the recommendations in SRP
-LR Section 3.1.2.2.1. The staff evaluates the TLAA analysis for the pressurizer components, pump casings, piping, thermowells, valve bodies, restricting orifices, fittings, and branch connections in SER Sections 4.3.1, 4.3.2, and 4.3.3.
With regard to LRA Table 3.1.1, item 3.1.1
-9, the staff noted that GALL AMR item IV.A2
-21 identifies cumulative fatigue damage as an applicable aging effect for steel, stainless steel, nickel-alloy, and nickel
-alloy or stainless steel cladding reactor vessel components, flanges, nozzles, penetrations, pressure housings, safe ends, thermal sleeves, vessel shells, heads, and welds and recommends that the TLAA on metal fatigue be used to manage this aging effect.
The applicant included applicable line items in LRA Table 3.1.2-2 for control rod assemblies, nozzles, and reactor vessel components that received ASME Code Section III CUF analysis calculations consistent with the recommendations in the SRP
-LR. Based on its review, the staff finds the applicant's AMR analysis on cumulative fatigue damage of control rod assemblies, nozzles, and reactor vessel components acceptable because it is consistent with the recommendations in SRP
-LR Section 3.1.2.2.1. The staff evaluates the TLAA analysis for the control rod assemblies, nozzles, and reactor vessel components in SER Section 4.3.1. With regard to LRA Table 3.1.1, item 3.1.1
-10, the staff noted that GALL AMR item IV.D1
-8 identifies cumulative fatigue damage as an applicable aging effect for steel, stainless steel, nickel-alloy, and steel with nickel
-alloy or stainless steel cladding steam generator components and recommends that the TLAA on metal fatigue be used to manage this aging effect. The applicant included applicable line items in LRA Table 3.1.2-4 for steam generator components that received ASME Code Section III CUF analysis calculations consistent with the recommendations in the SRP
-LR. Based on its review, the staff finds the applicant's AMR analysis on cumulative fatigue damage of steam generator components acceptable because it is consistent with the recommendations in SRP
-LR Section 3.1.2.2.1. The staff evaluates the TLAA analysis for the steam generator components in SER Section 4.3.1.
Aging Management Review Results 3-237 Based on the programs identified, the staff concludes that the applicant has 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 determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.1.2.2.2  Loss of Material Due to General, Pitting, and Crevice Corrosion The staff reviewed LRA Section 3.1.2.2.2 against the criteria in SRP
-LR Section 3.1.2.2.2.
  (1) LRA Section 3.1.2.2.2.1 refers to Table 3.1.1, item 3.1.1
-12 and addresses steel steam generator tube bundle tie rod assemblies and anti
-vibration bars exposed to treated water, which are being managed for loss of material due to general, pitting, and crevice corrosion by the Water Chemistry Program and the Steam Generator Tube Integrity Program. In LRA Table 3.1.1, item 3.1.1-12, the applicant stated that the Steam Generator Tube Integrity Program will be used to verify the effectiveness of the Water Chemistry Program.
The staff reviewed LRA Section 3.1.2.2.2.1 against the criteria in SRP
-LR Section 3.1.2.2.2.1, which states that loss of material due to general, pitting, and crevice corrosion could occur in the steel PWR steam generator shell assembly exposed to secondary feedwater and steam. The SRP
-LR states that the existing program relies on control of reactor water chemistry to mitigate corrosion and that the effectiveness of the chemistry control program should be verified to ensure that corrosion does not occur. The GALL Report recommends further evaluation of programs to verify the effectiveness of the chemistry control program. The SRP
-LR states that a one
-time inspection program of selected components at susceptible locations is an acceptable method to determine whether an aging effect is not occurring or an aging effect is progressing very slowly so that the component's intended function will be maintained during the period of extended operation.
The staff reviewed the applicant's Water Chemistry and Steam Generator Tube Integrity programs and its evaluations are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. In its review of components associated with LRA item 3.1.1
-12, the staff noted that the applicant had extended the application of SRP
-LR Table 3.1.1, item 3.1.1-12, initially for the steel once
-through steam generator shell assemblies exposed to secondary feedwater and steam to secondary steel components, such as the tube bundle tie rod assembly and anti
-vibration bars exposed to treated water, for its Unit 1 replacement recirculating steam generators. The staff finds this substitution acceptable because the combination of material/environment/aging effect, as identified by the applicant, is consistent with the GALL Report recommendations. The staff also noted that the applicant had assigned generic note E to the AMR line item stating that the Steam Generator Tube Integrity Program would be used for aging management. Because the GALL Report credits use of the One
-Time Inspection Program to verify the Water Chemistry Program's effectiveness, the staff finds the applicant's use of generic note E to be acceptable.
The staff noted that the Water Chemistry Program implements primary water and secondary water chemistry control consistent with the recommendations of the current EPRI guidelines for PWR primary water and secondary water chemistry control and that operating within these guidelines provides mitigation for the aging effect of loss of
 
Aging Management Review Results 3-238 material due to general, pitting, and crevice corrosion for steel steam generator components. The staff further noted that the Steam Generator Tube Integrity Program includes periodic visual inspections that are capable of detecting loss of material for components within its scope. The staff finds the applicant's proposal to manage the aging effect of loss of material due to general, pitting, and crevice corrosion for the steel steam generator tube bundle tie rod assemblies and anti
-vibration bars by using the Water Chemistry Program and the Steam Generator Tube Integrity Program acceptable because:  (a) the Water Chemistry Program provides mitigation for this aging effect and its use is consistent with the recommendations of the GALL Report, and (b) the Steam Generator Tube Integrity Program provides periodic visual inspections that are capable of detecting loss of material due to corrosion and thereby verifying effectiveness of the Water Chemistry Program for these steam generator components.
    (2) SRP-LR Section 3.1.2.2.2.2 refers to Table 3.1.1, item 3.1.1
-13, which applies to BWR isolation condenser components and is not applicable to Salem, which is a PWR.
  (3) SRP-LR Section 3.1.2.2.2.3 refers to Table 3.1.1, items 3.1.1
-14 and 3.1.1
-15, which apply to BWR reactor vessel and RCPB components and are not applicable to Salem, which is a PWR.
  (4) LRA Section 3.1.2.2.2.2 refers to Table 3.1.1, item 3.1.1
-16 and addresses:  (a) steel steam generator components (secondary manways and covers, tubesheets, upper head, upper shell, conical shell, lower shell), piping components and connections, and main feedwater and main steam nozzles exposed to steam and treated water, which are being managed for loss of material due to general, pitting, and crevice corrosion by the Water Chemistry and the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD programs; and (b) steel feedwater inlet ring and supports exposed to treated water, which are being managed for loss of material due to general, pitting, and crevice corrosion by the Water Chemistry and the Steam Generator Tube Integrity programs. In LRA Table 3.1.1, item 3.1.1-16, the applicant stated that the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program will be used to verify the effectiveness of the Water Chemistry Program in the steel steam generator components (secondary manways and covers, tubesheets, upper head, upper shell, conical shell, lower shell), piping components and connections, and main feedwater and main steam nozzles and that the Steam Generator Tube Integrity Program will be used to verify the effectiveness of the Water Chemistry Program in the steel steam generator feedwater inlet ring and supports.
The staff reviewed LRA Section 3.1.2.2.2.2 against the criteria in SRP
-LR Section 3.1.2.2.2.4, which states that loss of material due to general, pitting, and crevice corrosion could occur in the steel PWR steam generator upper and lower shell and transition cone components exposed to secondary feedwater and steam and 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 according to NRC IN 90
-04, the program may not be sufficient to detect pitting and crevice corrosion if general and pitting corrosion of the shell is known to exist and that for Westinghouse Model 44 and 51 steam generators, the GALL Report recommends an augmented inspection.
The staff noted in LRA Section 2.3.1.4 that the Unit 1 steam generators are described as Westinghouse Model F recirculating steam generators and the Unit 2 steam generators are described as AREVA 61/19T steam generators. The staff confirmed that these descriptions are consistent with the steam generator descriptions in the applicant's Aging Management Review Results 3-239 UFSAR Section 5.5.2.2. Because the applicant's steam generators are not Westinghouse Model 44 or 51, the staff finds that the GALL Report's recommendations related to augmented inspections are not applicable for the applicant's steam generators. The staff noted that the applicant had extended the application of SRP
-LR Table 3.1.1, item 3.1.1
-16, initially for the steel steam generator upper and lower shell and transition cone exposed to secondary feedwater and steam, to other secondary steel steam generator components. The staff finds this addition acceptable because the combination of material/environment/aging effect, as identified by the applicant, is consistent with the GALL Report recommendations.
In a letter dated August 26, 2010, responding to RAIs 3.1.1.66-01 and 3.1.1.84
-01, and in a subsequent letter dated October 8, 2010, documenting follow
-up clarification, the applicant revised a number of AMR items in LRA Table 3.1.2-4 that refer to LRA Table 3.1.1, item 3.1.1
-16. The staff reviewed all of the changes to AMR items that refer to LRA Table 3.1.1, item 3.1.1
-16. The staff noted that for steel steam generator components exposed to treated water the applicant identified the aging effect of loss of material due to general, pitting and crevice corrosion. The staff also noted that in all instances the applicant proposed to manage the loss of material aging effect with a combination of the Water Chemistry Program and either the ASME Section XI, Subsections IWB, IWC and IWD Program or the Steam Generator Tube Integrity Program. The staff reviewed the applicant's Water Chemistry and ASME Section XI, Subsections IWB, IWC, and IWD programs and its evaluations are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.1, respectively. In its review of components associated with LRA item 3.1.1
-16, for which the applicant credits the Water Chemistry and ASME Section XI, Subsections IWB, IWC, and IWD programs, the staff found the applicant's proposal to manage aging using these programs acceptable because:  (a) the applicant's Water Chemistry Program follows current EPRI secondary water chemistry guidelines and provides mitigation for the aging effect loss of material due to corrosion, and (b) the inspections required by ASME Code Section XI are capable of detecting loss of material due to corrosion, if it should occur, and thereby are capable of verifying the effectiveness of the Water Chemistry Program.
The staff also reviewed the applicant's Steam Generator Tube Integrity Program and its evaluations are documented in SER Section 3.0.3.1.8. In its review of components associated with LRA item 3.1.1
-16, the staff noted that the applicant had assigned generic note E to the AMR line items stating that the Steam Generator Tube Integrity Program would be used to verify the effectiveness of the Water Chemistry Program.
Because the GALL Report credits use of the ASME Section XI, Subsections IWB, IWC, and IWD Program to verify the Water Chemistry Program's effectiveness, the staff finds the applicant's use of generic note E to be acceptable.
The staff noted that the steam generator components for which the applicant credits the Steam Generator Tube Integrity Program are the carbon steel Unit 1 feedwater rings, feedwater ring supports, and secondary internals, and the low alloy steel tubesheets.
The staff also noted that surface inspection of these components is not required by ASME Code Section XI. In its review of the Steam Generator Tube Integrity Program, the staff found that the program includes periodic visual inspections that are capable of detecting loss of material for components within its scope and that the components listed Aging Management Review Results 3-240 are within the scope of the applicant's Steam Generator Tube Integrity Program. The staff finds the applicant's proposal to manage the aging effect of loss of material due to general, pitting, and crevice corrosion of the carbon steel steam generator feedwater ring and supports, and the secondary internals, and of the low alloy steel  steam generator tubesheets using the Water Chemistry Program and the Steam Generator Tube Integrity Program acceptable because:  (a) the Water Chemistry Program provides mitigation for this aging effect and its use is consistent with the recommendations of the GALL Report, (b) the Steam Generator Tube Integrity Program provides periodic visual inspections that are capable of detecting loss of material due to corrosion and thereby verifying effectiveness of the Water Chemistry Program for these steam generator components, (c) the components are within the scope of the applicant's Steam Generator Tube Integrity Program, and (d) the Steam Generator Tube Integrity Program is not being used in lieu of inspections specified in ASME Code Section XI requirements.
Based on a review of the programs identified above, the staff concludes that the applicant's programs meet SRP
-LR Section 3.1.2.2.2 criteria. For those line items that apply to LRA Section 3.1.2.2.2, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.1.2.2.3  Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement The staff reviewed LRA Section 3.1.2.2.3 against the following criteria in SRP
-LR Section 3.1.2.2.3:
  (1) LRA Section 3.1.2.2.3.1 addresses loss of fracture toughness due to certain aspects of neutron irradiation embrittlement as an aging effect that the applicant will manage through conducting TLAAs, consistent with the SRP
-LR. The evaluation of these TLAAs is discussed in LRA Section 4.2. SRP-LR Section 3.1.2.2.3.1 states that "[c]ertain aspects of neutron irradiation embrittlement are TLAAs as defined in 10 CFR 54.3. TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c)(1). This TLAA is addressed separately in Section 4.2 of this SRP-LR."  As discussed in SER Section 4.2, loss of fracture toughness due to neutron irradiation embrittlement is limited to RPV beltline and extended beltline materials having a neutron fluence greater than 1 x 10 17 n/cm 2 (E > 1 MeV) at the end of the period of extended operation. SER Section 4.2 accepted the applicant's evaluation of RPV neutron embrittlement in terms of upper-shelf energy (USE)
, pressurized thermal shock (PTS), and pressure-temperature (P
-T) limits, which represent a complete set of analytical means for predicting and managing loss of fracture toughness due to neutron irradiation embrittlement. Therefore, the staff concludes that the applicant's program meets SRP-LR Section 3.1.2.2.3.1 criteria. The staff also confirmed that LRA Table 3.1.2-2 correctly identifies the item under this aging effect (IV.A2
-23 for RPV shell) in GALL Report Table IV.A2, "Reactor Vessel, Internals, and Reactor Coolant System/Reactor Vessel (PWR)."  LRA Table 3.1.2-2 did not list GALL Report item IV.A2-16 for RPV nozzles under this aging effect. This is acceptable because the estimated neutron fluence at the end of the period of extended operation for Salem Units 1 and 2 RPV nozzles is less than 1 x 10 17 n/cm 2 (E > 1 MeV).
 
Aging Management Review Results 3-241  (2) LRA Section 3.1.2.2.3.2 addresses loss of fracture toughness due to neutron irradiation embrittlement as an aging effect that the applicant will manage, consistent with the SRP-LR, by the Reactor Vessel Surveillance Program. This LRA Section states that th e Reactor Vessel Surveillance Program provides sufficient material data and dosimetry to: 
 
(a) monitor irradiation embrittlement at the end of the period of extended operation and (b) determine the need for operating restrictions on the inlet temperature, neutron spectrum, and neutron flux.
SRP-LR Section 3.1.2.2.3.2 states that:
  [l]oss of fracture toughness due to neutron irradiation embrittlement could occur in BWR and PWR vessel beltline shell, nozzle, and welds exposed to reactor coolant and neutron flux. In accordance with 10 CFR Part 50, Appendix H, an applicant is required to submit its proposed withdrawal schedule for approval prior to implementation. Untested capsules placed in storage must be maintained for future insertion. Thus, further staff evaluation is required for license renewal. Specific recommendations for an acceptable AMP are provided in Chapter XI, Section M31 of the GALL Report. As indicated in SER Section 3.0.3.2.9, the staff accepted the applicant's Reactor Vessel Surveillance Program as capable of providing sufficient plant
-specific material data and dosimetry to monitor the Salem RPVs' irradiation embrittlement at the end of the period of extended operation. Hence, the staff concludes that the applicant's program meets SRP-LR Section 3.1.2.2.3.2 criteria. The staff also confirmed that LRA Table 3.1.2-2 correctly identified the GALL Report Table IV.A2 item under this aging effect (IV.A2
-24 for RPV shell). However, similar to SER Section 3.1.2.2.3.1, LRA Table 3.1.2-2 did not list GALL Report item IV.A2
-17 for RPV nozzles under this aging effect. This is acceptable because the estimated neutron fluence at the end of the period of extended operation for Salem Units 1 and 2 RPV nozzles is less than 1 x 10 17 n/cm 2 (E > 1 MeV).
Based on the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.3 criteria. For those line items that apply to LRA Section 3.1.2.2.3, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.1.2.2.4  Cracking Due to Stress
-Corrosion Cracking and Intergranular Stress
-Corrosion Cracking The staff reviewed LRA Section 3.1.2.2.4 against the criteria in SRP
-LR Section 3.1.2.2.4.
  (1) LRA Section 3.1.2.2.4 addresses cracking due to SCC and intergranular SCC (IGSCC), stating that this aging effect is not applicable to Salem which is a PWR.
SRP-LR Section 3.1.2.2.4 states that cracking due to SCC and IGSCC may occur in the stainless steel and nickel
-alloy BWR top head enclosure vessel flange leak detection lines.
Aging Management Review Results 3-242  The staff finds that SRP
-LR Section 3.1.2.2.4, item 1 is not applicable to Salem because Salem is a PWR, and the staff guidance in this SRP
-LR Section is only applicable to BWR-designed reactors.
  (2) LRA Section 3.1.2.2.4 addresses cracking due to SCC and IGSCC, stating that this aging effect is not applicable to Salem which is a PWR.
SRP-LR Section 3.1.2.2.4 states that cracking due to SCC and IGSCC may occur in stainless steel BWR isolation condenser components exposed to reactor coolant.
The staff finds that SRP
-LR Section 3.1.2.2.4, item 2 is not applicable to Salem because Salem is a PWR, and the staff guidance in this SRP
-LR Section is only applicable to BWR-designed reactors.
Based on the above, the staff concludes that the staff's guidance criteria of SRP
-LR Section 3.1.2.2.4, items 1 and 2 do not apply to Salem because the guidance is applicable only to BWR-designed reactors and Salem
, a PWR, is not a BWR design
. 3.1.2.2.5  Crack Growth Due to Cyclic Loading The staff reviewed LRA Section 3.1.2.2.5 against the criteria in SRP
-LR Section 3.1.2.2.5.
LRA Section 3.1.2.2.5, associated with LRA Table 3.1.1, item 3.1.1
-21, addresses cracking due to cyclic loading in reactor vessel shell forgings clad with stainless steel using a high
-heat-input welding process exposed to reactor coolant. The applicant stated that this item is not applicable because the Reactor Vessel Shell is not fabricated of SA 508
-Cl 2 forgings clad with stainless steel using a high
-heat-input welding process. The staff reviewed UFSAR Section 5 and noted that the reactor vessel shell is not fabricated of SA 508
-Cl 2 forgings clad with stainless steel using a high
-heat-input welding process, and, therefore, finds the applicant's claim acceptable.
3.1.2.2.6  Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement and Void Swelling The staff reviewed LRA Section 3.1.2.2.6 against the criteria in SRP
-LR Section 3.1.2.2.6. LRA Section 3.1.2.2.6 addresses loss of fracture toughness due to neutron irradiation embrittlement and void swelling as an aging effect that the applicant will manage, consistent with the SRP
-LR, by the PWR Vessel Internals Program which is committed to:  (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval. This commitment is also identified in UFSAR Section A.2.1.7, "PWR Vessel Internals."
SRP-LR Section 3.1.2.2.6 states that:
[l]oss of fracture toughness due to neutron irradiation embrittlement and void swelling could occur in stainless steel and nickel alloy reactor vessel internals components exposed to reactor coolant and neutron flux. The GALL Report recommends no further aging management review if the applicant commits in the Aging Management Review Results 3-243 [U]FSAR Supplement to (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval.
As described in LRA Section 3.1.2.2.6, the applicant made a commitment to incorporate all three GALL Report requirements stated above to manage this aging effect. The PWR Vessel Internals Program contains this commitment (Commitment No.
7). Commitment No.
7 is also identified in the UFSAR Section A.2.1.7. Therefore, the staff concludes that the applicant's program meets the SRP
-LR Section 3.1.2.2.6 criteria for managing the aging effects due to neutron irradiation embrittlement and void swelling. The staff also examined LRA Table 3.1.2-3 to find out whether the RPV internals subjected to these aging effects are consistent with those listed in GALL Report Table IV.B2. The staff confirmed that LRA Table 3.1.2-3 identified a ll GALL Report Table IV.B2 items and the components under them for this aging effect (IV.B2
-3, IV.B2-6, IV.B2-9, IV.B2-17, IV.B2-18, and IV.B2
-22). For GALL Report item IV.B2
-6, the applicant identified in LRA Table 3.1.2-3, two additional RPV internals components (the core support locking nut and the bolts and dowels of the thermal shield) as being different but consistent with this GALL Report item for material, environment, and aging effect. For four of the remaining five GALL Report Table IV.B2 items, LRA Table 3.1.2-3 provides a set of subcomponents to represent a single component in GALL Report Table IV.B2. The applicant's approach of including additional components under the required AMP for GALL Report item IV.B2-6 is acceptable.
Based on a review of the programs identified above, the staff concludes that the applicant's programs meet SRP
-LR Section 3.1.2.2.6 criteria. For those line items that apply to LRA Section 3.1.2.2.6, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.1.2.2.7  Cracking Due to Stress
-Corrosion Cracking The staff reviewed LRA Section 3.1.2.2.7 against the criteria in SRP
-LR Section 3.1.2.2.7.
  (1) LRA Section 3.1.2.2.7.1 addresses cracking due to SCC in the stainless steel RPV flange leak detection lines and the bottom-mounted instrument (BMI) guide tubes. It further states that the SCC in the stainless steel RPV flange leak detection lines is managed by the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. For the BMI guide tubes, LRA Section 3.1.2.2.7.1 states that they "are nickel alloy and are included with Line Item 3.1.1
-31 [LRA Table 3.1.2-2]."  SRP-LR Section 3.1.2.2.7.1 states that "[c]racking due to SCC could occur in the PWR stainless steel reactor vessel flange leak detection lines and [BMI] guide tubes exposed to reactor coolant. The GALL Report recommends that a plant
-specific AMP be evaluated to ensure that this aging effect is adequately managed."
LRA Table 3.1.2-2 credits the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program for managing cracking due to SCC for RPV flange leak detection lines that are fabricated from stainless steel and exposed to borated water.
Aging Management Review Results 3-244 The staff noted that the normal internal environment for the flange leak detection lines is air and the lines would be exposed to reactor coolant only when there is a leak at the inner reactor vessel closure flange O
-ring. Hence, a water chemistry program is not essential because it is ineffective for mitigating SCC in stainless steel lines with stagnant coolant intermittently present. The staff concludes that the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program, which provides periodic inspections for leak indications to ensure the intended function of affected components will be maintained during the period of extended operation, is acceptable to manage SCC for these lines. The staff's evaluation and acceptance of the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program is documented in SER Section 3.0.3.1.1.
LRA Table 3.1.2-2, item 3.1.1
-31 credits the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program; the Nickel Alloy Aging Management Program; and the Water Chemistry Program for managing cracking due to SCC for BMI nozzles that are fabricated from nickel alloy and exposed to reactor coolant. For this aging effect, GALL Report item IV.A2
-19 (equivalent to LRA Table 3.1.2-2, item 3.1.1-31) requires the applicant to adopt the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program and the Water Chemistry Program and comply with applicable NRC Orders with a commitment in the UFSAR supplement to implement applicable:  (a) Bulletins and GLs and (b) staff-accepted industry guidelines. The two AMPs required by the GALL Report are among the proposed three Salem AMPs for managing cracking due to SCC for nickel
-alloy BMI nozzles. The third GALL Report requirement regarding the commitment is incorporated in the Nickel Alloy Aging Management Program and is repeated in UFSAR Supplement A.2.2.6. The staff's review and acceptance of these three AMPs are documented in SER Sections 3.0.3.1.1, 3.0.3.3.6, and 3.0.3.1.2. Therefore, the staff concludes that the applicant's program meets the SRP
-LR Section 3.1.2.2.7.1 criteria for managing the aging effect of cracking due to SCC. The staff also confirmed that the applicant's evaluation is consistent with GALL Report items IV.A2
-5 and IV.A2
-19.  (2) LRA Section 3.1.2.2.7.2 addresses the aging management of cracking due to SCC of CASS Class 1 piping and piping components exposed to reactor coolant. LRA Table 3.1.1, item 3.1.1
-24 also refers to LRA Section 3.1.2.2.7.2 and addresses the applicant's aging management of SCC in the CASS components. The applicant stated that the aging effect will be managed by implementing the Water Chemistry Program and Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program. The applicant also addressed the further evaluation requirements by indicating that the existing program relies on control of water chemistry to mitigate SCC and that SCC could occur for CASS components that do not meet the NUREG-0313 guidelines with regard to carbon content and ferrite content. The applicant further indicated that the GALL Report recommends further evaluation of a plant
-specific program for these components, which do not meet NUREG
-0313 guidelines, to ensure that this aging effect is adequately managed.
The staff reviewed LRA Section 3.1.2.2.7.2 against the criteria in SRP
-LR Section 3.1.2.2.7, item 2, which states that cracking due to SCC could occur in CASS Class 1 PWR RCS piping, piping components, and piping elements exposed to reactor coolant. The SRP
-LR recommends control of water chemistry to mitigate SCC. The SRP-LR also recommends further evaluation of a plant
-specific program for these components to ensure that the aging effect is adequately managed. The GALL Report, under item IV.C2
-3 (R-05), recommends monitoring and control of primary water Aging Management Review Results 3-245 chemistry and material selection according to NUREG
-0313, Revision 2 guidelines which recommend carbon content not greater than 0.035 percent and ferrite content not less than 7.5 percent for the resistance of CASS to SCC. The GALL Report also recommends that a plant
-specific AMP be further evaluated for other CASS components that do not meet these criteria.
In its review, the staff noted the applicant credited the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program to manage SCC of the CASS components under the further evaluation of LRA Section 3.1.2.2.7.2. The staff also noted that LRA Section B.2.1.6 states that the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program is consistent with GALL AMP XI.M12, "Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)," with no exception or enhancement. LRA Section B.2.1.6 also indicates that the applicant's program includes the inspections, flaw evaluations, and repairs and replacements in accordance with the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. However, the staff noted that the material screening criteria used to manage the thermal aging embrittlement of CASS, as described in GALL AMP XI.M12, are different from the material screening criteria used to further evaluate and manage the SCC of CASS as described under GALL Report item IV.C2
-3. The staff noted that in order to manage the SCC of CASS under GALL Report item IV.C2-3, the GALL Report recommends further evaluation for CASS that has carbon content greater than 0.035 percent or ferrite content less than 7.5 percent. In contrast, the material screening criteria of the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program are based on the combinations of molybdenum content, different threshold levels of ferrite content (14 percent and 20 percent), and casting methods (static casting and centrifugal casting). Therefore, the staff found the need to clarify how the applicant's material screening criteria used to further evaluate and manage the SCC of CASS and applicant's aging management method are consistent with the GALL Report.
By letter dated August 9, 2010, the staff issued RAI 3.1.2.2.7.2
-01 requesting that the applicant clarify how the applicant's material screening criteria used to further evaluate and manage the SCC are consistent with GALL Report item IV.C2
-3 which recommen ds that SCC of CASS with carbon content greater than 0.035 percent or ferrite content less than 7.5 percent be further evaluated and adequately managed. In the RAI, the staff also requested that the applicant clarify whether the SCC of the CASS components is managed by the inspections, flaw evaluations, and repairs and replacements in accordance with the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. The staff further requested that, if the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program is not used to manage the aging effect, the applicant justify why its program is adequate to manage the aging effect.
In its response to the RAI, dated September 7, 2010, the applicant stated that the material criteria used to further evaluate and manage the aging effect and mechanism of cracking due to SCC of CASS Class 1 components are consistent with GALL Report item IV.C2
-3. The applicant also stated that it reviewed the chemical compositions of the CASS components exposed to reactor coolant and it was determined that these CASS components do not meet the NUREG
-0313 guidelines. The applicant further indicated that GALL Report item IV.C2
-3 recommends a plant
-specific AMP is to be evaluated for CASS components that do not meet the NUREG
-0313 guidelines of carbon content of less than or equal to 0.035 percent and ferrite content of greater than Aging Management Review Results 3-246 or equal to 7.5 percent. In addition, the applicant indicated that LRA Table 3.1.2-1 inappropriately credited the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program as the plant
-specific program and that instead the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program will be credited to manage cracking due to SCC for the CASS Class 1 components exposed to reactor coolant.
The applicant also stated that in LRA Table 3.1.2-1, the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program is appropriately credited to manage the aging effect and mechanism of loss of fracture toughness due to thermal aging embrittlement. The applicant stated that the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program uses inspections, flaw evaluations, and repairs and replacements, as required. The applicant further indicated that LRA Table 3.1.1, item 3.1.1
-24; LRA Table 3.1.2-1; and LRA Section 3.1.2.2.7.2 are revised as a result of the RAI response.
Based on its review, the staff finds the applicant's response to RAI 3.1.2.2.7.2
-01 acceptable because the applicant clarified that:  (a) the material screening criteria used to manage the SCC are consistent with the GALL Report, and (b) the revised LRA credits the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program, which is adequate to detect and manage the effects of SCC through the inspections, flaw evaluations, and repair and replacement activities. The staff's concerns described in RAI 3.1.2.2.7.2
-01 are resolved.
The staff reviewed the Water Chemistry Program and the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program and the staff's evaluations are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.1, respectively. In its review, the staff finds the applicant's use of the Water Chemistry Program acceptable to manage the aging effect because:  (a) the monitoring and controlling of water chemistry are performed periodically in accordance with the EPRI PWR water chemistry guidelines as recommended by GALL AMP XI.M2, and (b) the chemistry control minimizes the concentrations of detrimental contaminants and mitigates the occurrence of SCC in the components. In addition, the staff finds the applicant's use of the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program acceptable to manage the aging effect because:  (a) the applicant clarified that the applicant's material screening criteria used to further evaluate and manage SCC are consistent with the GALL Report; (b) the applicant's program includes periodic inspections, flaw evaluations, and repair and replacement activities in accordance with the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program; (c) the periodic inspections for CASS components ensure timely detection of cracks; (d) the evaluations for detected flaws ensure that the intended functions of the components are adequately maintained for the period of extended operation; and (e) the repair and replacement activities provide adequate corrective actions for the aging management. In its review, the staff finds that the applicant's AMR results are consistent with GALL Report item IV.C2
-3 and the applicant satisfied the acceptance criteria in SPR
-LR Section 3.1.2.2.7.2.
Based on the programs identified above, the staff concludes that the applicant's programs meet the criteria in SRP
-LR Section 3.1.2.2.7. For those line items that apply to LRA Section 3.1.2.2.7, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the Aging Management Review Results 3-247 intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.1.2.2.8  Cracking Due to Cyclic Loading The staff reviewed LRA Section 3.1.2.2.8 against the criteria in SRP
-LR Section 3.1.2.2.8.
  (1) LRA Section 3.1.2.2.8 addresses cracking due to cyclic loading stating that this aging effect is not applicable to Salem, which is a PWR.
SRP-LR Section 3.1.2.2.8 states that cracking due to cyclic loading may occur in the stainless steel BWR jet pump sensing lines.
The staff verified that SRP
-LR Section 3.1.2.2.8, Item (1) is not applicable to Salem because it is a PWR and the staff guidance in this SRP
-LR Section is only applicable to BWR-designed reactors that are designed with stainless steel jet pump sensing lines.
  (2) Section 3.1.2.2.8 addresses cracking due to cyclic loading stating that this aging LRA effect is not applicable to Salem, which is a PWR.
SRP-LR Section 3.1.2.2.8 states that cracking due to cyclic loading may occur in steel and stainless steel BWR isolation condenser components exposed to reactor coolant.
The staff verified that SRP
-LR Section 3.1.2.2.8, Item (2) is not applicable to Salem  because it is a PWR and the staff guidance in this SRP
-LR Section is only applicable to BWR-designed reactors that are designed with isolation condensers.
Based on the above, the staff concludes that SRP
-LR Section 3.1.2.2.8 criteria does not apply to Salem. 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 in stainless steel and nickel-alloy PWR RPV components exposed to reactor coolant and neutron flux as an aging effect that the applicant will manage, consistent with the SRP
-LR, by the commitment of the PWR Vessel Internals Program.
SRP-LR Section 3.1.2.2.9 states that:
[l]oss of preload due to stress relaxation could occur in stainless steel and nickel alloy PWR reactor vessel internals screws, bolts, tie rods, and holddown springs exposed to reactor coolant. The GALL Report recommends no further [AMR] if the applicant provides a commitment in the [U]FSAR Supplement to (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended Aging Management Review Results 3-248 operation, submit an inspection plan for reactor internals to the NRC for review and approval.
As described in LRA Section 3.1.2.2.9, the applicant made a commitment to incorporate all three GALL Report requirements stated above to manage this aging effect. The PWR Vessel Internals Program contains this commitment (Commitment No.
7). Commitment No.
7 is also identified in UFSAR Section A.2.1.7. Therefore, the staff concludes that the applicant's program meets the SRP
-LR Section 3.1.2.2.9 criteria for managing the aging effects due to loss of preload due to stress relaxation. The staff also examined LRA Table 3.1.2-3 to find out whether the RPV internals subjected to these aging effects are consistent with those listed in GALL Report Table IV.B2. The staff confirmed that LRA Table 3.1.2-3 identified all GALL Report Table IV.B2 items and the components under them for this aging effect (IV.B2
-5, IV.B2-14, IV.B2-25, IV.B2-33, and IV.B2
-38). For GALL Report item IV.B2
-5, the applicant identified the bolts and dowels of the thermal shield as the component which is different but consistent with this GALL Report item for material, environment, and aging effect. For three of the remaining four GALL Report Table IV.B2 items, LRA Table 3.1.2-3 provides a set of subcomponents to represent a single component in GALL Report Table IV.B2. The applicant's approach of including additional components under the required AMP for GALL Report item IV.B2-5 is acceptable.
Based on a review of the program identified above, the staff concludes that the applicant's program meets SRP
-LR Section 3.1.2.2.9 criteria. For those line items that apply to LRA Section 3.1.2.2.9, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.1.2.2.10 Loss of Material Due to Erosion The staff reviewed LRA Section 3.1.2.2.10 against the criteria in SRP
-LR Section 3.1.2.2.10.
LRA Section 3.1.2.2.10, associated with LRA Table 3.1.1, item 3.1.1
-28, addresses loss of material due to erosion in steel steam generator feedwater 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 the steam generators. The staff reviewed UFSAR, Section 5 and noted that the applicant's steam generators do not contain steel steam generator feedwater impingement plates and supports and, therefore, finds the applicant's claim acceptable.
3.1.2.2.11 Cracking Due to Flow
-Induced Vibration The staff reviewed LRA Section 3.1.2.2.11 against the criteria in SRP
-LR Section 3.1.2.2.11. LRA Section 3.1.2.2.11 addresses cracking due to flow-induced vibration by stating that this aging effect is not applicable to Salem, which is a PWR. SRP
-LR Section 3.1.2.2.11 states that cracking due to flow
-induced vibration could occur for the BWR stainless steel steam dryers exposed to reactor coolant. The staff finds that SRP
-LR Section 3.1.2.2.11 is not applicable because Salem is a PWR and the staff guidance in this SRP
-LR Section is only applicable to the design of steam dryers in BWR-designed reactors.
 
Aging Management Review Results 3-249 Based on the above, the staff concludes that the guidance in SRP
-LR Section 3.1.2.2.11 does not apply to Salem.
3.1.2.2.12 Cracking Due to Stress
-Corrosion Cracking and Irradiation
-Assisted Stress-Corrosion Cracking The staff reviewed LRA Section 3.1.2.2.12 against the criteria in SRP
-LR Section 3.1.2.2.12. LRA Section 3.1.2.2.12 addresses cracking due to SCC and IASCC in stainless steel RPV internals exposed to reactor coolant and neutron flux as an aging effect that the applicant will manage, consistent with the SRP
-LR, by the Water Chemistry Program and the commitment of the PWR Vessel Internals Program. SRP
-LR Section 3.1.2.2.12 states that:
[c]racking due to SCC and IASCC could occur in PWR stainless steel reactor internals exposed to reactor coolant. The existing program relies on control of water chemistry to mitigate these effects. The GALL Report recommends no further [AMR] if the applicant provides a commitment in the [U]FSAR Supplement to (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval.
As indicated in SER Section 3.0.3.1.2, the staff accepts the Water Chemistry Program for mitigating the aging effects due to SCC and IASCC, meeting one of the requirements mentioned in SRP-LR Section 3.1.2.2.12. Furthermore, as described in LRA Section 3.1.2.2.12, the applicant made a commitment to incorporate all three GALL Report requirements stated above to manage this aging effect (IV.B2
-2, IV.B2-8, IV.B2-10, IV.B2-12, IV.B2-24, IV.B2-30, IV.B2-36 , and IV.B2-42). For GALL Report items IV.B2
-10 and IV.B2
-30, the applicant identified additional RPV internal components which are different but consistent with these GALL Report items for material, environment, and aging effect. For most of the GALL Report items mentioned above, LRA Table 3.1.2-3 provides a set of subcomponents to represent a single component in GALL Report Table IV.B2. The applicant's approach of including additional components under the required AMP for GALL Report items IV.B2
-10 and IV.B2-30 is conservative and acceptable. However, the staff found that LRA Table 3.1.2-3 does not distinguish the aging effect discussed in this SER Section from that in LRA Section 3.1.2.2.17, "Cracking Due to Stress Corrosion Cracking, Primary Water Stress Corrosion Cracking, and Irradiation
-Assisted Stress Corrosion Cracking."  Therefore, the staff issued RAI 3.1.2.2.12
-1 requesting that the applicant provide a revised LRA Table 3.1.2
-3 to identify the aging effect discussed in LRA Section 3.1.2.2.17, or justify combining LRA Sections 3.1.2.2.12 and 3.1.2.2.17 under the table column title "Aging Effect Requiring Management" in LRA Table 3.1.2-3. Although the response, dated July 15, 2010, to RAI 3.1.2.2.12
-1 did not provide direct justification, the staff determines that the proposed industry program for managing PWR internals as documented in MRP
-227 is structured around components, not around aging effects. Therefore, not identifying PWSCC as an aging effect for certain components in LRA Table 3.1.2-3 has no impact on the AMP to be implemented for managing PWR internals. MRP-227 is currently under the NRC's review in a separate effort.
Hence, RAI 3.1.2.2.12
-1 is resolved. 
 
Aging Management Review Results 3-250 Based on a review of the programs identified above, the staff concludes that the applicant's programs meet SRP
-LR Section 3.1.2.2.12 criteria. For those line items that apply to LRA Section 3.1.2.2.12, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.1.2.2.13 Cracking Due to Primary Water Stress
-Corrosion Cracking The staff reviewed LRA Section 3.1.2.2.13 against the criteria in SRP
-LR Section 3.1.2.2.13, which recommends no further AMR if the applicant complies with applicable NRC Orders and provides a commitment in the UFSAR supplement to implement applicable:  (1) Bulletins and GLs and (2) staff-accepted industry guidelines.
The staff noted that the applicant's commitment (Commitment No.
: 46) in LRA Appendix A, Section A.5 commits to the implementation of the Nickel Alloy Aging Management Program and that various portions of that program contain language which is consistent with the commitment described in SRP
-LR Section 3.1.2.2.13. The staff also notes that all of the AMR results lines that refer to Table 3.1.1, item 3.1.1
-31 are aligned with the applicant's commitment as described in LRA Appendix A, Section A.5. The staff finds the applicant's proposal acceptable because the applicant provided the appropriate commitment in the UFSAR supplement and the AMR results lines refer to the commitment.
3.1.2.2.14 Wall Thinning Due to Flow
-Accelerated Corrosion LRA Section 3.1.2.2.14 refers to Table 3.1.1, item 3.1.1
-32 and addresses the steel steam generator feedwater inlet ring and supports exposed to treated water, which are being managed for wall thinning due to flow
-accelerated corrosion by the Steam Generator Tube Integrity Program. In LRA Table 3.1.1, item 3.1.1
-32 and LRA Section 3.1.2.2.14, the applicant stated that the Steam Generator Tube Integrity Program will be used to manage wall thinning in the feedwater inlet ring and supports. The applicant further stated that the Steam Generator Tube Integrity Program implements a number of industry guidelines and incorporates a balance of prevention, inspection, evaluation, repair, and leakage monitoring measures to assure that existing environmental conditions are not causing wall thinning that could result in loss of component intended function.
The staff reviewed LRA Section 3.1.2.2.14 against the criteria in SRP
-LR Section 3.1.2.2.14, which states that wall thinning due to flow
-accelerated corrosion could occur in the steel feedwater inlet rings and supports. The GALL Report refers to NRC IN 91-19, "Steam Generator Feedwater Distribution Piping Damage," for evidence of flow
-accelerated corrosion in steam generators and recommends that a plant
-specific AMP be evaluated because existing programs may not be capable of mitigating or detecting wall thinning due to flow
-accelerated corrosion.
The staff reviewed the applicant's Steam Generator Tube Integrity Program and its evaluation is documented in SER Section 3.0.3.1.8. In its review of components associated with LRA item 3.1.1-32, the staff noted that the GALL Report recommends that a plant
-specific AMP be evaluated and the applicant credits the Steam Generator Tube Integrity Program to manage wall thinning in these components.
The staff noted that the Steam Generator Tube Integrity Program description in LRA Section B.2.1.10 states that the program includes managing the aging effect of wall thinning.
Aging Management Review Results 3-251 However, the LRA does not describe what inspection or analytical techniques are used to ensure that excessive wall thinning in components does not occur.
By letter dated June 29, 2010, the staff issued RAI 3.1.2.2.14
-01 requesting that the applicant describe its examination techniques and evaluation methodology used to manage wall thinning in the steam generator feedwater inlet rings and supports.
In its response to the RAI, dated July 28, 2010, the applicant stated that the Steam Generator Tube Integrity Program uses visual inspections of the steam generators' secondary
-side internals and that it does not include predictive analytical techniques. The applicant further stated that the Unit 1 steam generators are Westinghouse Model F, with feedwater rings and supports constructed of carbon steel, and that the Unit 2 steam generators are AREVA Model 61/19T, with feedwater ring supports constructed of low
-alloy steel plates and feedwater rings constructed of 316L stainless steel. The applicant also stated that the aging effect and mechanism of wall thinning due to flow
-accelerated corrosion does not apply to the stainless steel Unit 2 steam generator feedwater ring.
The applicant stated that the visual inspection techniques and associated acceptance criteria are determined by a steam generator degradation assessment which evaluates internal and external operating experience, industry guidance, design features, and materials of construction. The applicant stated that these inspections identify the general condition of the applicable steam generator components and inspect for evidence of erosio n-corrosion, irregular geometry, and structural changes and that the acceptance criteria require that there be no visible signs of deterioration in the Unit 1 feedwater rings or in the Units 1 and 2 feedwater ring supports. The applicant further stated that it performs an operational assessment in accordance with NEI 97
-06, "Steam Generator Program Guidelines," and applicable EPRI documents to confirm that acceptance criteria are met for the steam generators to return to service and operate for the subsequent cycle and that the operational assessment ensures that deficiencies are identified and corrective actions are taken before loss of component intended function occurs. The applicant also stated that while preparing its response, it noted that LRA Table 3.1.2-4, "Summary of Aging Management Evaluations for Steam Generators," did not correctly include the material differences between Unit 1 feedwater rings (carbon steel) and Unit 2 feedwater rings (stainless steel). The applicant revised this table to show that wall thinning due to flow
-accelerated corrosion is applicable for the Unit 1 carbon steel feedwater rings and for the Units 1 and 2 carbon steel or low
-alloy steel supports, but is not applicable for the Unit 2 stainless steel feedwater rings. These carbon steel and low
-alloy steel components are in a treated water environment (secondary feedwater/steam) and the aging effect will be managed by the Steam Generator Tube Integrity Program. The applicant also added lines showing that loss of material due to pitting and crevice corrosion and cracking due to SCC are aging effects applicable for the Unit 2 stainless steel feedwater rings. These stainless steel components are in a treated water environment and those aging effects will be managed by a combination of the Water Chemistry Program and the One
-Time Inspection Program.
In its review of the applicant's response, the staff noted that GALL AMP XI.M19, "Steam Generator Tube Integrity," references NEI 97
-06. The staff determined that NEI 97
-06 provides acceptable guidance for inspection and assessment of additional steam generator components, including the feedwater rings and supports, consistent with the GALL Report. The staff further noted that industry operating experience supports the applicant's claim that flow
-accelerated corrosion is not applicable to the Unit 2 stainless steel feedwater rings. The staff finds the Steam Generator Tube Integrity Program acceptable to manage aging of the Unit 1 carbon stee l feedwater rings and supports and the Unit 2 low-alloy steel feedwater ring supports because the Aging Management Review Results 3-252 program:  (1) provides visual inspections of the subject steam generator components based on recommendations of NEI 97
-06, (2) includes assessments of inspection results against appropriate acceptance criteria, and (3) provides for corrective actions to be taken, as needed, to ensure that the subject components remain capable of performing their intended functions between scheduled steam generator inspecti ons. In its review of the applicant's changes to LRA Table 3.1.2-4, the staff noted that the AMR result lines added for the stainless steel feedwater rings are consistent with GALL Report items VIII.F-23 and VIII.F
-24 for stainless steel steam generator blowdown (SGBD) system components in a treated water environment; and these lines are included in the evaluations in SER Sections 3.4.2.2.6 and 3.4.2.2.7, for LRA Table 3.4.1, items 3.4.1
-14 and 3.4.1
-16, respectively. The staff finds the applicant's change to LRA Table 3.1.2-4 acceptable because this change:  (1) documents the material difference between the steel feedwater rings in Unit 1 and the stainless steel feedwater rings in Unit 2 and (2) shows AMR results that are consistent with recommendations in the GALL Report.
Based on its review, the staff finds the applicant's response to RAI 3.1.2.2.14
-01 acceptable as described above. The staff's concern described in RAI 3.1.2.2.14
-01 is resolved.
Based on the program identified above, the staff concludes that the applicant's program meets SRP-LR Section 3.1.2.2.14 criteria. For those line items that apply to LRA Section 3.1.2.2.14, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.1.2.2.15 Changes in Dimensions Due to Void Swelling The staff reviewed LRA Section 3.1.2.2.15 against the criteria in SRP
-LR Section 3.1.2.2.15. LRA Section 3.1.2.2.15 addresses changes in dimensions due to void swelling in stainless steel and nickel
-alloy PWR reactor internal components exposed to reactor coolant as an aging effect that the applicant will manage, consistent with the SRP
-LR, by the commitment of the PWR Vessel Internals Program.
SRP-LR Section 3.1.2.2.15 states that:
[c]hanges in dimensions due to void swelling could occur in stainless steel and nickel alloy PWR reactor internal components exposed to reactor coolant. The GALL Report recommends no further [AMR] if the applicant provides a commitment in the [U]FSAR Supplement to (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval.
As described in LRA Section 3.1.2.2.15, the applicant made a commitment to incorporate all three GALL Report requirements stated above to manage this aging effect. The PWR Vessel Internals Program contains this commitment (Commitment No.
7). Commitment No.
7 is also identified in UFSAR Section A.2.1.7. Therefore, the staff concludes that the applicant's program Aging Management Review Results 3-253 meets the SRP
-LR Section 3.1.2.2.15 criteria. The staff also examined LRA Table 3.1.2-3 to find out whether the RPV internals subjected to these aging effects are consistent with those listed in GALL Report Table IV.B2. The staff confirmed that LRA Table 3.1.2-3 identified all GALL Report Table IV.B2 items and the components under them for this aging effect (IV.B2
-1, IV.B2-4, IV.B2-7, IV.B2-11, IV.B2-15, IV.B2-19, IV.B2-23, IV.B2-27, IV.B2-29, IV.B2-35, IV.B2-39, and IV.B2
-41). For GALL Report items IV.B2
-4, IV.B2-19, and IV.B2
-29, the applicant identified additional RPV internal components which are different but consistent with these GALL Report items for material, environment, and aging effect. For most of the GALL Report Table IV.B2 items mentioned above, LRA Table 3.1.2-3 provides a set of subcomponents to represent a single component in GALL Report Table IV.B2. The applicant's approach of including additional components under the required AMP for GALL Report items IV.B2
-4, IV.B2-19, and IV.B2
-29 is acceptable.
Based on a review of the program identified above, the staff concludes that the applicant's program meets SRP
-LR Section 3.1.2.2.15 criteria. For those line items that apply to LRA Section 3.1.2.2.15, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.1.2.2.16 Cracking Due to Stress
-Corrosion Cracking and Primary Water Stress
-Corrosion Cracking The staff reviewed LRA Section 3.1.2.2.16 against the criteria in SRP
-LR Section 3.1.2.2.16.  (1) LRA Section 3.1.2.2.16.1 refers to Table 3.1.1, item 3.1.1
-34 and addresses stainless steel and nickel
-alloy reactor CRD head penetration pressure housings, which are managed for cracking due to SCC and PWSCC. The LRA states that the applicant will implement the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program and Water Chemistry Program to manage the cracking due to SCC in the stainless steel reactor CRD head penetration pressure housings.
The staff reviewed LRA Section 3.1.2.2.16.1 against the criteria in SRP
-LR Section 3.1.2.2.16.1, which states that cracking due to SCC could occur on the primary coolant side of PWR steel steam generator upper and lower heads, tubesheets, and tube-to-tubesheet welds made or clad with stainless steel. The SRP
-LR also states that cracking due to PWSCC could occur on the primary coolant side of PWR steel steam generator upper and lower heads, tubesheets, and tube
-to-tubesheet welds made or clad with nickel alloy. The staff noted that the GALL Report recommends the ASME Section XI Inservice Inspection, Subsections IWB, IWC and IWD program and Water Chemistry Program to manage these aging effects. In addition, the GALL Report indicates that no further AMR of nickel alloys is required if the applicant complies with applicable NRC Orders and provides a commitment in the UFSAR supplement to implement applicable NRC Bulletins, GLs, and NRC staff
-accepted industry guidelines.
The staff further reviewed the LRA and identified in Table 3.1.1, item 3.1.1
-34 and Table 3.1.2-2 that the applicant addressed SCC of stainless steel reactor CRD head penetration pressure housings exposed to reactor coolant and credited the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program and Water Chemistry Program to manage the aging effect. The staff reviewed the applicant's Aging Management Review Results 3-254 ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program and Water Chemistry Program and its evaluations are documented in SER Sections 3.0.3.1.1 and 3.0.3.1.2, respectively. In its review, the staff finds that the credited programs are adequate to manage the aging effect because:  (a) the Water Chemistry Program monitors the plant water chemistry parameters against the established parameter limits and, if a parameter exceeds the limit, the program performs adequate actions such that the water chemistry control continues to mitigate the aging effect; (b) the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program includes inspections of selected components to verify the effectiveness of the Water Chemistry Program consistent with the GALL Report; and (c) the inspections in accordance with ASME Code Section XI can ensure that significant degradation does not occur and the intended function of the component is maintained during the extended period of operation consistent with the GALL Report.
In LRA Table 3.1.1, the applicant further stated that Item Number 3.1.1
-35 is not applicable because Salem Units 1 and 2 SGs are not a once-through design and therefore, do not have the components associated with this model of SGs.
The staff noted that the GALL Report revision 1 volume 2 indicates th at item 3.1.1-35 is only applicable to once
-through SGs, but not to recirculating SGs.
UFSAR Section 5.5.2.2.2 described that the Unit 1 Model-F steam generator tubes are fabricated from Alloy 600TT and are welded to the Inconel cladding on the primary face of the tube plate. UFSAR Section 5.5.2.2.1 described that the Unit 2 replacement steam generator tubes are fabricated from Alloy 690TT, and that the primary side of the tube sheet is weld clad with Alloy 600.
The staff noted that ASME Code Section XI does not require any inspection of the tube-to-tubesheet welds.
In addition, no specific NRC Orders or bulletins require examination of this weld. The staff's concern is that, if the tubesheet cladding is Alloy 600, the autogenous tube
-to-tubesheet weld may not have sufficient Chromium content to prevent initiation of PWSCC, even when the SG tubes are made from Alloy 690TT, as it is the configuration for the applicant's Unit 2 SG tubes. Consequently, such a PWSCC crack initiated in this region, close to a tube, could propagate into/through the weld, causing a failure of the weld and of the reactor coolant pressure boundary, even for recirculating SGs such as those for both units. Therefore, unless the NRC has approved a redefinition of the pressure boundary in which the autogenous tube
-to-tubesheet weld is no longer included, or the tubesheet cladding and welds are not susceptible to PWSCC, the staff considers that the effectiveness of the primary water chemistry program should be verified to ensure PWSCC cracking is not occurring.
The staff will issue an RAI requesting that the applicant clarify for Unit 1 SGs whether the tube-to-tubesheet welds are included in the reactor coolant pressure boundary or alternate repair criteria have been permanently approved and, if there is no alternate repair criteria permanently approved, that the applicant provide a plant
-specific AMP that will complement the primary water chemistry program, in order to verify the effectiveness of the primary water chemistry program and ensure that cracking due to PWSCC is not occurring in tube
-to-tubesheet welds. For Unit 2 SGs tube
-to-tubesheet welds, the staff requested the applicant provide either a plant
-specific AMP that will complement the primary water chemistry program, in order to verify the effectiveness of the primary water chemistry program and ensure that cracking due to PWSCC is not occurring in tube-to-tubesheet welds, or a rationale for why such a program is not needed. This has been identified as Open Item 3.1.2.2.16
-1.
Aging Management Review Results 3-255  The staff concludes, with the exception of Open Item OI 3.1.2.2.16
-1, that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that their intended functions will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3
).  (2) LRA Section 3.1.2.2.16.2 refers to Table 3.1.1, item 3.1.1
-36 and addresses the SCC in the stainless steel pressurizer spray head exposed to reactor coolant. The LRA further states that it will implement the Water Chemistry Program and One
-Time Inspection Program to manage the aging effect.
The staff reviewed LRA Section 3.1.2.2.16.2 against the criteria in SRP
-LR Section 3.1.2.2.16.2, which states that cracking due to SCC could occur on stainless steel pressurizer spray heads. The SRP
-LR also states that the exiting program relies on control of water chemistry to mitigate this aging effect. The SRP
-LR further states that the GALL Report recommends a one
-time inspection to confirm that the cracking does not occur. The staff also noted that the GALL Report, under item IV.C2
-17, recommends the water chemistry program and the one
-time inspection program to manage the aging effect of the stainless steel component. The staff noted that the GALL Report recommends the One
-Time Inspection Program to verify the effectiveness of the water chemistry control program.
The staff reviewed the LRA and identified in Table 3.1.1, item 3.1.1
-36 and Table 3.1.2-1 that the applicant credited the Water Chemistry Program and One
-Time Inspection Program to manage the SCC in the stainless steel pressurizer spray head exposed to reactor coolant. The staff also reviewed the applicant's Water Chemistry Program and One-Time Inspection Program and its evaluations are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.11, respectively. The applicant indicated that the One-Time Inspection Program includes a one
-time inspection of more susceptible materials in potentially more aggressive environments to manage the aging effect. The staff finds that the credited programs are adequate to manage the aging effect because: 
(a) the Water Chemistry Program monitors the plant water chemistry control parameters against the established parameter limits and, if a parameter exceeds the limit, the program performs adequate actions such that the water chemistry control continues to mitigate the aging effect; (b) the One-Time Inspection Program includes a one
-time inspection of selected components to verify the effectiveness of the Water Chemistry Program consistent with the GALL Report; and (c) the one-time inspection can ensure that significant degradation does not occur and the component's intended function is maintained during the period of extended operation. On the basis of its review, the staff finds that the applicant's AMR results are consistent with those under GALL Report, Volume 2, item IV.C2
-17 and the applicant satisfied the acceptance criteria in SRP
-LR Section 3.1.2.2.16.2.
Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.16 criteria. For those items that apply to LRA Section 3.1.2.2.16, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
Aging Management Review Results 3-256 3.1.2.2.17 Cracking Due to Stress
-Corrosion Cracking, Primary Water Stress-Corrosion Cracking, and Irradiation
-Assisted Stress
-Corrosion Cracking The staff reviewed LRA Section 3.1.2.2.17 against the criteria in SRP
-LR Section 3.1.2.2.17. LRA Section 3.1.2.2.17 addresses cracking due to SCC, PWSCC, and IASCC in stainless steel and nickel
-alloy PWR reactor internal components exposed to reactor coolant and neutron flux as an aging effect that the applicant will manage, consistent with the SRP
-LR, with the Water Chemistry Program and the commitment of the PWR Vessel Internals Program. SRP-LR Section 3.1.2.2.17 states that:
[c]racking due to [SCC, PWSCC, and IASCC] could occur in PWR stainless steel and nickel alloy reactor vessel internals components. The existing program relies on control of water chemistry to mitigate these effects. However, the existing program should be augmented to manage these aging effects for reactor vessel internals components. The GALL Report recommends no further AMR if the applicant provides a commitment in the [U]FSAR Supplement to (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval.
As indicated in SER Section 3.0.3.1.2, the staff accepts the Water Chemistry Program for mitigating the aging effects due to SCC, PWSCC, and IASCC, meeting one of the requirements mentioned in SRP
-LR Section 3.1.2.2.17. Furthermore, the applicant made a commitment to incorporate all three GALL Report requirements stated above to manage this aging effect. The PWR Vessel Internals Program contains this commitment (Commitment No.
7). Commitment No. 7 is also identified in UFSAR Section A.2.1.7. Therefore, the staff concludes that the applicant's program meets the SRP
-LR Section 3.1.2.2.17 criteria. The staff also confirmed that LRA Table 3.1.2-3 identified all GALL Report Table IV.B2 items and the components under them for this aging effect (IV.B2
-16, IV.B2-20, IV.B2-28, and IV.B2
-40). For GALL Report item IV.B2-20, the applicant identified additional RPV internal components which are different but consistent with these GALL Report items for material, environment, and aging effect. For most of the GALL Report Table IV.B2 items mentioned above, LRA Table 3.1.2-3 provides a set of subcomponents to represent a single component in GALL Report Table IV.B2. The applicant's approach of including additional components under the required AMP for GALL Report item IV.B2
-20 is conservative and acceptable.
It was mentioned in SER Section 3.1.2.2.12 that LRA Table 3.1.2-3 does not distinguish the aging effects discussed in LRA Sections 3.1.1.1.12 and 3.1.2.2.17. This has no impact on the AMP managing the PWR internals under these two aging effects as explained in SER Section 3.1.2.2.12.
Based on a review of the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.1.2.2.17 criteria. For those line items that apply to LRA Section 3.1.2.2.17, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that Aging Management Review Results 3-257 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 through J, that the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report. The applicant provided further information concerning how the aging effects will be managed. Specifically, Note F indicates that the material for the AMR line item component is not evaluated in the GALL Report. Note G indicates that the environment for the AMR line item component and material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR line item component, material, and environment combination is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the line item component, material, and environment combination is not applicable. Note J indicates that neither the component nor the material and environment combination for the line item is evaluated in the GALL Report.
For component type, material, and environment combinations not evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine whether the applicant had demonstrated that the aging effects will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation. The staff's evaluation is discussed in the following sections.
3.1.2.3.1  Reactor Coolant System
-Summary of Aging Management Evaluation
-LRA Table 3.1.2-1 The staff reviewed LRA Table 3.1.2-1 which summarizes the results of AMR evaluations for the RCS component groups.
In LRA Tables 3.1.2-1, 3.5.2-3, and 3.5.2
-4 , the applicant stated that stainless steel bolting components exposed to indoor air are being managed for loss of material by the Bolting Integrity Program and loss of preload due to self
-loosening by the ASME Section XI, SubSection IWE and 10 CFR Part 50, Appendix J programs, or the Structures Monitoring Program. The AMR line items cite generic note H. The staff reviewed the applicant's Bolting Integrity; ASME Section XI, SubSection IWE; 10 CFR Part 50, Appendix J; and Structures Monitoring programs and its evaluations are documented in SER Sections 3.0.3.2.2, 3.0.3.2.13, 3.0.3.1.18, and 3.0.3.2.15, respectively. The staff finds the applicant's proposed programs acceptable to manage aging for these components because:  (1) each program or combination of programs has incorporated industry guidance on proper selection of bolting material and lubricants and installation practices, and (2) the programs include detailed visual inspections of bolting to detect loss of material and loss of preload.
 
Aging Management Review Results 3-258 In LRA Table 3.1.2-1, the applicant stated that copper alloy valve body components exposed to lubricating oil (internal) are being managed for loss of material due to pitting, crevice, and microbiologically
-influenced corrosion by the Lubricating Oil Analysis and One
-Time Inspection programs. The AMR line items cite generic note H, indicating that for this item the aging effect is not in the GALL Report for this material, component, and environmental condition.
The staff reviewed all AMR result line items in the GALL Report where the component and material is copper alloy and valve body components exposed to lubricating oil (internal) and confirmed that there are no aging effect entries in the GALL Report for this component, material, and environment combination.
The staff's evaluation of the applicant's Lubricating Oil Analysis and One
-Time Inspection programs are documented in SER Sections 3.0.3.2.12 and 3.0.3.1.11, respectively. The staff notes that the Lubricating Oil Analysis Program includes oil sampling and analysis for viscosity, total acid number (TAN), and total water analysis. This program also performs wear particle count (WPC) analysis to identify wear metals such as iron, chromium, and lead and contaminants such as silicon, calcium, and z i n c. Thus, the staff finds the applicant's Lubricating Oil Analysis and One
-Time Inspection programs acceptable to manage aging for these components because:  (1) the Lubricating Oil Analysis Program will monitor the quality of the oil to determine if the components succumb to wear issues, as well as identify detrimental contaminants in the fluid that would lead to loss of material; and (2) the One
-Time Inspection Program will determine if the Lubricating Oil Analysis Program is effective at preventing loss of material. The analysis of the oil and visual inspections are consistent with the GALL Report and thus, the monitoring program will adequately manage the aging effect.
The staff's evaluation for glass exposed to air with borated water leakage, air or gas
-wetted and closed cycle cooling water with no aging effect and no AMP proposed is documented in SER Section 3.3.2.3.4.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AM R results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.1.2.3.2  Reactor Coolant System
-Reactor Vessel
-Summary of Aging Management Evaluation
-LRA Table 3.1.2-2 The staff reviewed LRA Table 3.1.2-2 which summarizes the results of AMR evaluations for the reactor vessel component groups.
In LRA Table 3.1.2-2, the applicant stated that for nickel
-alloy nozzles exposed to air with borated water leakage, there is no aging effect and no AMP is proposed. The AMR line items cite generic note G. These line items also cite plant
-specific note 3, which states that this environment is not in the GALL Report for this component and material. The note also states that nickel
-alloy material located indoors and subject to an air with borated water leakage environment is not subject to aging effects beyond those experienced in a reactor coolant environment that includes cracking/SCC. The note further states that these aging effects are already accounted for and are managed by the Nickel Alloy Aging Management Program that inspects the external surfaces of the nickel
-alloy materials.
 
Aging Management Review Results 3-259 The staff reviewed the associated line items in the LRA and confirmed that no aging effect is applicable for this component, material, and environment combination because nickel alloys are not subject to external corrosion resulting from external exposure to air with borated water leakage and because the applicant recognizes the potential for internal cracking of nickel
-alloy components which are internally exposed to reactor coolant. Additionally, other aging effects addressed by the GALL Report are not known to occur in nickel alloys externally exposed to air with borated water leakage.
The staff finds the applicant's proposal acceptable because:  (1) the loss of material which is known to occur to steel components exposed to air with borated water leakage does not occur when nickel alloys are externally exposed to air with borated water leakage; (2) other aging effects which are addressed by the GALL Report, such as cracking, are not known to occur when nickel alloys are externally exposed to air with borated water leakage; (3) the applicant is aware of, and is adequately managing, the aging effect of cracking which is known to occur to nickel alloys which are internally exposed to reactor coolant; and (4) the inspections conducted to identify internal cracking of these components are conducted from the external surface and would identify any aging effect that may result from external exposure of these components to air with borated water leakage.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.1.2.3.3  Reactor Coolant System-Reactor Vessel Internals
-Summary of Aging  Management Evaluation
-LRA Table 3.1.2-3 The staff reviewed LRA Table 3.1.2-3 which summarizes the results of AMR evaluations for the reactor vessel internals component groups.
In LRA Table 3.1.2-3, the applicant stated that the nickel
-alloy RCCA guide tube assemblies and lower internal assemblies including clevis blocks, inserts for clevis blocks, and clevis block lock keys exposed to reactor coolant and neutron flux are being managed for loss of material due to wear by the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. The AMR line items cite generic note H. These items also cite plant
-specific note 3, which states that the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program is used to manage the aging effects for this component, material, and environment combination.
The staff reviewed these line items and finds that the aging effect proposed by the applicant is possible, although its occurrence is not common and the extent of aging is normally not significant. The staff also reviewed other LRA items associated with these components and found that, when all associated line items are considered, the applicant has identified all credible aging effects. The staff's evaluation of the applicant's ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program is documented in SER Section 3.0.3.1.1. The staff notes that these components are subject to a variety of aging effects including cracking, loss of material due to various forms of corrosion, and changes in dimension in addition to the aging effect currently under consideration. The staff also notes that a variety of AMPs are proposed by the Aging Management Review Results 3-260 applicant to address these aging effects including the Water Chemistry and PWR Vessel Internals programs in addition to the AMP currently under consideration. The staff finds the applicant's proposal to manage aging using this AMP acceptable because the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program is capable of detecting loss of material due to wear in this component, material, and environment combination and because the same components are being inspected for other aging effects by programs which are also capable of detecting this aging effect.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.1.2.3.4  Reactor Coolant System
-Steam Generators-Summary of Aging Management Evaluation
-LRA Table 3.1.2-4 The staff reviewed LRA Table 3.1.2-4 which summarizes the results of AMR evaluations for the steam generator component groups.
In LRA Table 3.1.2-4, the applicant stated that the nick el-alloy spray nozzles, tube bundle tie rod assembly and anti
-vibration bars, and steam generator tubes exposed to internal and external treated water are being managed for loss of material due to pitting and crevice corrosion and reduction in heat transfer due to fouling by the Water Chemistry and Steam Generator Tube Integrity programs. The AMR line items cite generic note H. These line items also cite plant-specific notes 2, 5, or 6. Plant
-specific note 2 states that the GALL Report does not have an AMP for loss of material/pitting and crevice corrosion for nickel alloys in a treated water (secondary feedwater/steam) environment. Plant
-specific note 2 also states that the Water Chemistry and Steam Generator Tube Integrity programs will be used to manage the aging effects applicable to this component type, material, and environment combination.
Plant-specific note 5 states that the aging effect/mechanism of loss of material due to pitting and crevice corrosion is not in the GALL Report for this component, material, and environment, however, it is applicable to this combination. Plant
-specific note 5 also states that the Water Chemistry and Steam Generator Tube Integrity programs are used to manage the aging effects for this component, material, and environment combination. Plant
-specific note 6 states that the aging effect/mechanism of reduction of heat transfer due to fouling is not in the GALL Report for this component, material, and environment, however, it is applicable to this combination. This note also states that the Water Chemistry Program and Steam Generator Tube Integrity Program are used to manage the aging effects for this component, material, and environment combination.
The staff reviewed these line items and finds that the aging effects proposed by the applicant are possible, although their occurrence is not common and the extent of aging is normally not significant, especially for the reduction of heat transfer due to fouling of steam generator tubes exposed to reactor coolant. The staff also reviewed other LRA items associated with these components and found that, when all associated line items are considered, the applicant has identified all credible aging effects.
The staff's evaluation of the applicant's Water Chemistry and Steam Generator Tube Integrity programs are 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 these AMPs acceptable because identical Aging Management Review Results 3-261 AMPs are proposed in the GALL Report for similar components in similar environments to manage cracking and because the aging effects identified by the applicant (loss of material and reduction of heat transfer due to fouling) can be readily managed by programs which are capable of identifying and managing SCC.
The staff notes that one of the components, spray nozzles, appears to be outside the scope of the Steam Generator Tube Integrity AMP which states that the "program is specific to SG tubes, plugs, sleeves, and tube supports". The staff finds this wording in the scope of the AMP to be overly limiting in that the scope also addresses the implementation of NEI 97
-06 in accordance with GL 97
-06. The staff finds that since the nozzles under consideration are within the scope of NEI 97
-06 and GL 97
-06, they are also within the scope of the AMP.
In LRA Table 3.1.2-4, the applicant stated that the nickel alloy steam generator tubes exposed to treated water (external) and to reactor coolant (internal) are being managed for reduction of heat transfer effectiveness due to fouling of heat transfer surfaces by the Steam Generator Tube Integrity Program and the Water Chemistry Program. The AMR line items cite generic note H. Plant specific note 6 is also cited, which states that the aging effect/mechanism of reduction of heat transfer due to fouling is not in the GALL Report for this component, material, and environment, however, it is applicable to this combination.
The staff reviewed the associated line items in the LRA and noted that it was not clear whether the aging mechanism of fouling from the inside diameter (ID) surface of the steam generator tubes, which is in contact with the reactor coolant, had been detected at any U.S.
nuclear plant and should be taken into account. In addition, it was unclear to the staff whether the applicant has observed any fouling of its steam generator tubes on their primary side, secondary side or both. Moreover, the staff noted that the applicant did not explain how the Water Chemistry Program and specifically, the Steam Generator Tube Integrity Program could manage ID fouling of the steam generator tubes.
During a telephone conference on August 29 , 2010 between the applicant and the staff, the staff discussed why the applicant has selected the aging mechanism of fouling of the steam generator tubes from the inside surface and how the AMPs it credited, especially the Steam Generator Tube Integrity Program, could manage this mechanism.
Consequently, by letter dated August 26, 2010, the applicant stated that it had inappropriately added the aging effect and mechanism of loss of heat transfer due to fouling for the nickel alloy steam generator tubes in the reactor coolant (internal) environment to LRA Table 3.1.2-4, and had therefore deleted them from LRA Table 3.1.2-4. The applicant revised its LRA Table 3.1.2-4 accordingly.
The applicant also stated that the appropriate line items in Table 3.1.2
-4 are maintained for the applicable aging effects and mechanisms, that is the aging effect and mechanism of loss of heat transfer due to fouling for the nickel alloy steam generator tubes in the treated water (external) environment are correctly shown for its both units' steam generators in LRA Table 3.1.2-4. The staff reviewed the applicant's clarification and finds it acceptable because the applicant had selected the only pertinent aging effect of reduction of heat transfer effectiveness due to fouling of heat transfer surfaces, which occurs from outside tubes surface, as identifed in NRC Information Notice 2007
-37, and managed it with the appropriate programs, consistent with industry guidelines such as EPRI PWR Water Chemistry Guidelines and NEI 97-06, "Steam Generator Program Guidelines," as recommended in GALL AMPs XI.M2 and XI.M19.
 
Aging Management Review Results 3-262 The staff's evaluation of the applicant's Water Chemistry Program and Steam Generator Tube Integrity Program are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. The staff notes that the Water Chemistry Program manages the aging effects of reduction of heat transfer and includes provisions specified by the GALL Report for the verification of proper chemistry control and aging management, such that the intended functions of plant components will be maintained during the period of extended operation for Salem. The staff also noted that the aging effects managed by the Steam Generator Tube Integrity Program include reduction of heat transfer, and this program implements industry guidelines that include a secondary side integrity plan addressing degradations on steam generator secondary side that could affect tubing, consistent with GALL AMP XI.M19. The staff finds the applicant's proposal to manage aging using the Steam Generator Tube Integrity Program and Water Chemistry Program acceptable because the applicant selected the only relevant aging effect of reduction of heat transfer effectiveness due to fouling of heat transfer surfaces from outside steam generator tubes surface, and managed it with the appropriate GALL AMPs XI.M2 and XI.M19.
In LRA Table 3.1.2-4, the applicant stated that for nickel
-alloy steam generator components (primary channel head drain, plug, and welds) exposed to air with borated water leakage, there is no aging effect and no AMP is proposed. The AMR line items cite generic note G. These line items also cite plant
-specific note 4 which states that this environment is not in the GALL Report for this component and material. The note also states that nickel
-alloy material located indoors and subject to an air with borated water leakage environment is not subject to aging effects beyond those experienced in a reactor coolant environment that includes cracking/SCC. The note further states that these aging effects are already accounted for and are managed by the Nickel Alloy Aging Management Program that inspects the external surfaces of the nickel
-alloy materials.
The staff reviewed the associated line items in the LRA and confirmed that no aging effect is applicable for this component, material, and environment combination because nickel alloys are not subject to external corrosion resulting from external exposure to air with borated water leakage and because the applicant recognizes the potential for internal cracking of nickel
-alloy components which are internally exposed to reactor coolant. Additionally, other aging effects addressed by the GALL Report are not known to occur in nickel alloys externally exposed to air with borated water leakage.
The staff finds the applicant's proposal acceptable because:  (1) the loss of material which is known to occur to steel components exposed to air with borated water leakage does not occur when nickel alloys are externally exposed to air with borated water leakage; (2) other aging effects which are addressed by the GALL Report, such as cracking, are not known to occur when nickel alloys are externally exposed to air with borated water leakage; (3) the applicant is aware of, and is adequately managing, the aging effect of cracking which is known to occur to nickel alloys which are internally exposed to reactor coolant; and (4) the inspections conducted to identify internal cracking of these components are conducted from the external surface and would identify any aging effect that may result from external exposure of these components to air with borated water leakage.
In LRA Table 3.1.2-4, the applicant stated that stainless steel steam generator tube bundle tie rod assemblies and anti
-vibration bars exposed to treated water at greater than 60
&deg; C (140&deg; F) are being managed for loss of material by the Water Chemistry and Steam Generator Tube Integrity programs. The AMR line items cite generic note H.
 
Aging Management Review Results 3-263 The staff reviewed the applicant's Water Chemistry and Steam Generator Tube Integrity programs which are evaluated in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. The staff noted that the applicant's Water Chemistry Program monitors and controls the concentration of contaminants in the water in accordance with EPRI guidelines in order to mitigate loss of material. The staff also noted that the applicant's Steam Generator Tube Integrity Program includes good foreign material exclusion practices, non-destructive Examination (NDE) of tubes, inservice inspection (ISI), and leakage monitoring to mitigate and detect the effects of loss of material on steam generator components. The staff finds the monitoring programs acceptable to manage loss of material because they include both preventive measures (i.e., water chemistry control and good foreign material exclusion practices) to prevent loss of material, as well as NDEs, visual inspections, and leakage monitoring to detect if loss of material is occurring.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
====3.1.3 Conclusion====
The staff concludes that the applicant has provided sufficient information to demonstrate that the effects of aging for the RCS, reactor vessel, reactor vessel internals, and steam generator components within the scope of license renewal and subject to an AMR will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
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 ESF components and component groups of the:
containment spray system  residual heat removal system safety injection system 3.2.1  Summary of Technical Information in the Application LRA Section 3.2 provides AMR results for the ESF components and component groups. LRA Table 3.2.1, "Summary of Aging Management Evaluations for the Engineered Safety Features," provides a summary comparison of its AMRs to those evaluated in the GALL Report for 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 issue reports and discussions with appropriate site personnel to identify AERMs. The Aging Management Review Results 3-264 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 whether the applicant provided sufficient information to demonstrate that the effects of aging for ESF components within the scope of license renewal and subject to an AMR will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
The staff conducted an onsite audit of AMPs to ensure the applicant's claim that certain AMPs were consistent with the GALL Report. The purpose of this audit was to examine the applicant's AMPs and related documentation and to verify the applicant's claim of consistency with the corresponding GALL Report AMPs. The staff did not repeat its review of the matters described in the GALL Report. The staff's evaluations of the AMPs are documented in SER Section 3.0.3. The staff reviewed the AMRs to confirm the applicant's claim that certain identified AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant had identified the appropriate GALL Report AMRs. Details of the staff's evaluation are discussed in SER Sections 3.2.2.1 and 3.2.2.2.
The staff also reviewed the AMRs not consistent with or not addressed in the GALL Report. The review evaluated whether all plausible aging effects were identified and whether the aging effects listed were appropriate for the combination of materials and environments specified. Details of the staff's evaluation are discussed in SER Section 3.2.2.3. For components which the applicant claimed were not applicable or required no aging management, the staff reviewed the AMR line items and the plant's operating experience to verify the applicant's claims.
Table 3.2-1 summarizes the staff's evaluation of components, aging effects or mechanisms, and AMPs listed in LRA Section 3.2 and addressed in the GALL Report.
Table 3.2-1  Staff Evaluation for Engineered Safety Features 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 the emergency core cooling system (ECCS) (3.2.1-1) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) Yes TLAA Fatigue is a TLAA (see SER Section 3.2.2.2.1)
 
Aging Management Review Results 3-265 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 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 Salem (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 Not applicable Not applicable to Salem (see SER Section 3.2.2.2.3(1))
Stainless steel piping, piping components, and piping elements exposed to soil (3.2.1-4) Loss of material due to pitting and crevice corrosion A plant-specific AMP is to be evaluated.
Yes Not applicable Not applicable to Salem (see SER Section 3.2.2.2.3(2))
Stainless steel and aluminum piping, piping components, and piping elements exposed to treated water (3.2.1-5) Loss of material due to pitting and crevice corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (see SER Secti on 3.2.2.2.3(3))
Stainless steel and copper alloy piping, piping components, and piping elements exposed to lubricating oil (3.2.1-6) Loss of material due to pitting and crevice corrosion Lubricating Oil Analysis and One-Time Inspection Yes Not applicable Not applicable to Salem (see SER Section 3.2.2.2.3(4))
Partially encased stainless steel tanks with breached moisture barrier exposed to raw water (3.2.1-7) Loss of material due to pitting and crevice corrosion A plant-specific AMP is to be evaluated for pitting and crevice corrosion of tank bottoms because moisture and water can egress under the tank due to cracking of the perimeter seal from weathering.
Yes Not applicable Not applicable to Salem (see SER Section 3.2.2.2.3(5))
 
Aging Management Review Results 3-266 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 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 Periodic Inspection Consistent with the GALL Report (see SER Section 3.2.2.2.3(6))
Steel, stainless steel, and copper alloy heat exchanger tubes exposed to lubricating oil (3.2.1-9) Reduction of heat transfer due to fouling Lubricating Oil Analysis and One-Time Inspection Yes Not applicable Not applicable to Salem (see SER Section 3.2.2.2.4(1))
Stainless steel heat exchanger tubes exposed to treated water (3.2.1-10) Reduction of heat transfer due to fouling Water Chemistry and One-Time Inspection Yes One-Time Inspection and Water Chemistry Consistent with the GALL Report (see SER Section 3.2.2.2.4(2))
Elastomer seals and components in the standby gas treatment system exposed to air
-indoor uncontrolled (3.2.1-11) Hardening and loss of strength due to elastomer degradation A plant-specific AMP is to be evaluated. Yes Not applicable Not applicable to PWRs (see SER Section 3.2.2.2.5)
Stainless steel high-pressure safety injection (HPSI) (charging) pump miniflow orifice exposed to treated borated water (3.2.1-12) Loss of material due to erosion A plant-specific AMP is to be evaluated for erosion of the orifice due to extended use of the centrifugal HPSI pump for normal charging. Yes Water Chemistry Consistent with the 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(1))
 
Aging Management Review Results 3-267 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 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 Not applicable Not applicable to Salem (see SER Section 3.2.2.2.8(2))
Steel piping, piping components, and piping elements exposed to lubricating oil (3.2.1-16) Loss of material due to general, pitting, and crevice corrosion Lubricating Oil Analysis and One-Time Inspection Yes Not applicable Not applicable to Salem (see SER Section 3.2.2.2.8(3))
Steel (with or without coating or wrapping) piping, piping components, and piping elements buried in soil (3.2.1-17) Loss of material due to general, pitting, crevice, and microbiologically
 
-influenced corrosion Buried Piping and Tanks Surveillance or Buried Piping and Tanks Inspection No    Yes Not applicable Not applicable to Salem (see SER Section 3.2.2.2.9)
Stainless steel piping, piping components, and piping elements exposed to treated water > 60 &deg;C (140 &deg;F) (3.2.1-18) Cracking due to SCC and IGSCC BWR Stress Corrosion Cracking 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) >
250 &deg;C (482 &deg;F) (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
 
Not applicable Not applicable to Salem (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 Salem (see SER Section 3.2.2.1.1)
 
Aging Management Review Results 3-268 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 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 the GALL Report Steel closure bolting exposed to air
-indoor uncontrolled (external) (3.2.1-24) Loss of preload due to thermal effects, gasket creep, and self-loosening Bolting Integrity No Bolting Integrity; 10 CFR Part 50 , Appendix J; and ASME Section XI, SubSection IW E Consistent with the GALL Report Stainless steel piping, piping components, and piping elements exposed to closed-cycle cooling water > 60 &deg;C (140 &deg;F) (3.2.1-25) Cracking due to SCC Closed-Cycle Cooling Water System No Closed-Cycle Cooling Water System Consistent with the 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 Not applicable Not applicable to Salem (see SER Section 3.2.2.1.1)
Steel heat exchanger components exposed to closed-cycle cooling water (3.2.1-27) Loss of material due to general, pitting, crevice, and galvanic corrosion Closed-Cycle Cooling Water System No Not applicable Not applicable to Salem (see SER Section3.2.2.1.1)
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 Syst em Consistent with the 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 Not applicable Not applicable to Salem (see SER Section 3.2.2.1.1)
 
Aging Management Review Results 3-269 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 the 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 the 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 Not applicable Not applicable to Salem (see SER Section 3.2.2.1.1)
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 Salem (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 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Consistent with the GALL Report 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 Not applicable Not applicable to Salem (see SER Section 3.2.2.1.1)
 
Aging Management Review Results 3-270 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 microbiologically
 
-influenced corrosion and fouling Open-Cycle Cooling Water System No Not applicable Not applicable to Salem (see SER Section 3.2.2.1.1)
Stainless steel piping, piping components, and piping elements exposed to raw water (3.2.1-37) Loss of material due to pitting, crevice, and microbiologically
-influenced corrosion Open-Cycle Cooling Water System No Not applicable Not applicable to Salem (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 microbiologically
-influenced corrosion and fouling Open-Cycle Cooling Water Syste m No Not applicable Not applicable to Salem (see SER Section 3.2.2.1.1)
Stainless steel heat exchanger components exposed to raw water (3.2.1-39) Loss of material due to pitting, crevice, and microbiologically
-influenced corrosion and fouling Open-Cycle Cooling Water System No Not applicable Not applicable to Salem (see SER Section 3.2.2.1.1)
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 Salem (see SER Section 3.2.2.1.1)
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 Not applicable Not applicable to Salem (see SER Section 3.2.2.1.1)
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 Salem (see SER Section 3.2.2.1.1)
 
Aging Management Review Results 3-271 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 Salem (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 Salem (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 the 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 Not applicable Not applicable to Salem (see SER Section 3.2.2.1.1)
CASS piping, piping components, and piping elements exposed to treated borated water > 250 &deg;C (482 &deg;F) (3.2.1-47) Loss of fracture toughness due to thermal aging embrittlement Thermal Aging Embrittlement of CASS No Not applicable Not applicable to Salem (see SER Section 3.2.2.1.1)
Stainless steel or stainless-steel-clad steel piping, piping components, piping elements, and tanks (including safety injection tanks/accumulators) exposed to treated borated water
> 60 &deg;C (140 &deg;F) (3.2.1-48) Cracking due to SCC Water Chemistry No Water Chemistry Consistent with the GALL Report 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 Consistent with the GALL Report (see SER Section 3.2.2.2.3(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 Aluminum piping, piping components, and piping elements exposed to air
-indoor uncontrolled (internal/external)
(3.2.1-50) None None NA None Consistent with the GALL Report Galvanized steel ducting exposed to air-indoor controlled (external)
(3.2.1-51) None None NA None Not applicable to Salem (see SER Section 3.2.2.1.1)
Glass piping elements exposed to air-indoor uncontrolled (external), lubricating oil, raw water, treated water, or treated borated water (3.2.1-52) None None NA None Consistent with the GALL Report Stainless steel, copper alloy, and nickel-alloy piping, piping components, and piping elements exposed to air
-indoor uncontrolled (external)
(3.2.1-53) None None NA None Consistent with the GALL Report Steel piping, piping components, and piping elements exposed to air
-indoor controlled (external)
(3.2.1-54) None None NA None Not applicable to Salem (see SER Section 3.2.2.1.1)
Steel and stainless steel piping, piping components, and piping elements in concrete (3.2.1-55) None No ne NA None Not applicable to Salem (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 NA None Consistent with the GALL Report
 
Aging Management Review Results 3-273 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 < 15% Zn piping, piping components, and piping elements exposed to air with borated water leakage (3.2.1-57) None None NA None Consistent with the GALL Report The staff's review of the ESF component groups followed several approaches. One approach, documented in SER Section 3.2.2.1, discusses the staff's review of AMR results for components the applicant indicated are consistent with the GALL Report and require no further evaluation.
Another approach, documented in SER Section 3.2.2.2, discusses the staff's review of AMR results for components the applicant indicated are consistent with the GALL Report and for which further evaluation is recommended. A third approach, documented in SER Section 3.2.2.3, discusses the staff's review of AMR results for components the applicant indicated are not consistent with or not addressed in the GALL Report. The staff's review of AMPs credited to manage or monitor aging effects of the ESF components is documented in SER Section 3.0.3. 3.2.2.1  AMR Results That Are Consistent with the GALL Report In LRA Section 3.2.2.1, the applicant identified the materials, environments, and AERMs. The applicant identified the following programs that manage the aging effects of ESF components:
Aboveground Non
-Steel Tanks ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Bolting Integrity Boric Acid Corrosion Closed-Cycle Cooling Water System External Surfaces Monitoring Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components On e-Time Inspection One-Time Inspection of ASME Code Class 1 Small-Bore Piping Periodic Inspection Water Chemistry LRA Tables 3.2.2-1 to 3.2.2
-3 summarize AMRs for the ESF components and indicate AMRs claimed to be consistent with the GALL Report.
For component groups evaluated in the GALL Report for which the applicant had claimed consistency and for which the GALL Report does not recommend further evaluation, the staff performed a review to determine whether the plant
-specific components in these GALL Report component groups were bounded by the GALL Report evaluation.
 
Aging Management Review Results 3-274 The applicant provided a note for each AMR line item. The notes describe how the information in the tables aligns with the information in the GALL Report. The staff audited those AMRs with Notes A through E, which indicate how the AMR was consistent with the GALL Report.
Note A indicates that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. The staff audited these line items to verify consistency with the GALL Report and the validity of the AMR for the site
-specific conditions.
Note B indicates that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report and that it had reviewed and accepted the identified exceptions to the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant was consistent with the AMP identified in the GALL Report and whether the AMR was valid for the site-specific conditions.
Note C indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the AMP identified by the GALL Report. This note indicates that the applicant was unable to find a listing of some system components in the GALL Report; however, the applicant identified a different component in the GALL Report that had the same material, environment, aging effect, and AMP as the component under review. The staff audited these line items to verify consistency with the GALL Report. The staff also determined whether the AMR line item of the different component applied to the component under review and whether the AMR was valid for the site
-specific conditions.
Not e D indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff confirmed whether the AMR line item of the different component was applicable to the component under review and whether it had reviewed and accepted the 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 E indicates that the AMR line item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited. The staff audited these line items to verify consistency with the GALL Report. The staff also 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 notes that in LRA Tables 3.2.2-1 and 3.2.2
-3, there are AMR line items for stainless steel tanks exposed to treated borated water  The staff also notes that the LRA does not have a line item for the tank material exposed to an air or wetted gas internal environment as would occur when the tank is partially full. The staff further notes that in the case of LRA Table 3.2.2 1, the LRA line items manage the aging of the tank internals using the Water Chemistry and One
-Time Inspection programs. The staff finds the existing line items acceptable because:  (1) the Water Chemistry Program will minimize contaminant concentrations and thus mitigate loss of material due to various corrosion mechanisms for tank internal surfaces at the fluid to air transition zone, and (2) the One
-Time Inspection Program will Aging Management Review Results 3-275 provide reasonable assurance that an aging effect is not occurring or that the aging effect is occurring slowly enough to not affect a components intended function. The staff notes that in the case of the tanks included in LRA Table 3.2.2-3, the LRA line items manage the aging of the tank internals using the Water Chemistry Program. The staff finds these existing line items acceptable because:  (1) the Water Chemistry Program will minimize contaminant concentrations and thus mitigate loss of material due to various corrosion mechanisms for tank internal surfaces at the fluid to air transition zone, (2) the use of only the Water Chemistry Program is consistent with GALL Report item V.D1
-30 and there are no other GALL Report line items in Section V.D1 related to tanks that require anything more than the Water Chemistry Program, and (3) the GALL Report recommends that there is no AERM or recommended AMP for stainless steel tanks exposed to air
-indoor uncontrolled or condensation.
The staff concludes that 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).
LRA Tables 3.2.2-1 to 3.2.2
-3 provide a summary of the AMR results for component types associated with the ESF. The summary information for each component type included intended function, material, environment, AERM, AMPs, GALL Report Volume 2 item, cross reference to LRA Table 3.2.1, and generic and plant
-specific notes related to consistency with the GALL Report. The staff reviewed the information in the LRA. The staff did not repeat its review of the matters described in the GALL Report; however, it did verify that the material presented in the LRA was applicable and that the applicant had identified the appropriate GALL Report AMRs.
On the basis of its review, the staff determines that, for AMRs not requiring further evaluation, as identified in LRA Table 3.2.1, the applicant's references to the GALL Report are acceptable and no further evaluation is required.
3.2.2.1.1  AMR Results Identified as Not Applicable LRA Table 3.2.1, item 3.2.1
-17 addresses loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion in steel (with or without coating or wrapping) piping, piping components, and piping elements buried in soil. The applicant stated that this line item is not applicable because there are no steel piping, piping components, and piping elements buried in soil in the ESF systems. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant's LRA does not have any AMR results for ESF systems that include steel (with or without coating or wrapping) piping, piping components, and piping elements buried in soil. The staff also reviewed the applicant's UFSAR and confirmed that no in
-scope steel (with or without coating or wrapping) piping, piping components, and piping elements buried in soil are present in the ESF systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.2.1, items 18 through 20, discusses the applicant's determination on GALL AMR line items that are applicable only to BWR
-designed reactors. In the applicant AMR discussions for items 18 through 20, no additional information is provided. The staff confirmed that AMR items 18 through 20, in Table 1 of the GALL Report, Volume 1 are only applicable to BWR designed reactors, and that Salem is a PWR with a dry ambient containment. Based on this Aging Management Review Results 3-276 determination, the staff finds that AMR items 18 through 20, in Table 1 of the GALL Report, Volume 1 are not applicable to Salem.
LRA Table 3.2.1, item 3.2.1
-21 addresses high
-strength steel closure bolting exposed to air with steam or water leakage in the ESF systems. The GALL Report recommends use of GALL AMP XI.M18, "Bolting Integrity," to manage cracking due to cyclic loading or SCC for this component group. The applicant stated that this item is not applicable because there is no high-strength closure bolting in the ESF systems. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant's LRA does not have any AMR results for the ESF systems that include high
-strength steel closure bolting exposed to air with steam or water leakage. The staff reviewed the applicant's UFSAR and confirmed that no in
-scope high
-strength steel closure bolting exposed to air with steam or water leakage is present in the ESF systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.2.1, item 3.2.1
-22 addresses steel closure bolting exposed to air with steam or water leakage. The GALL Report recommends use of GALL AMP XI.M18, "Bolting Integrity," to manage loss of material due to general corrosion for this component group. The applicant stated that this item is not applicable because there is no steel closure bolting exposed to air with steam or water leakage in the ESF systems. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant's LRA does not have any AMR results for the ESF systems that include steel closure bolting exposed to air with steam or water leakage. The staff reviewed the applicant's UFSAR and confirmed that no in
-scope steel closure bolting exposed to air with steam or water leakage is present in the ESF systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.2.1, item 3.2.1-26 addresses loss of material due to general, pitting, and crevice corrosion in steel piping, piping components, and piping elements exposed to closed
-cycle cooling water. The applicant stated that this item is not applicable because there are no corresponding components in the ESF systems exposed to closed
-cycle cooling water. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant's LRA does not have any AMR results that include steel piping, piping components, or piping elements exposed to closed-cycle cooling water in the ESF systems. The staff also reviewed the UFSAR and confirmed that no in
-scope steel piping, piping components, or piping elements exposed to clos ed-cycle cooling water are present in the ESF systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.2.1, item 3.2.1-27 addresses loss of material due to general, pitting, crevice, and galvanic corrosion in steel heat exchanger components exposed to closed
-cycle cooling water. The applicant stated that this item is not applicable because there are no corresponding components in the ESF systems exposed to closed
-cycle cooling water. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant's LRA does not have any AMR results that include steel heat exchanger components exposed to closed
-cycle cooling water in the ESF systems. The staff also reviewed the UFSAR and confirmed that no in
-scope steel heat exchanger components exposed to closed
-cycle cooling water are present in the ESF systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.2.1, item 3.2.1-29 addresses loss of material due to pitting, crevice, and galvanic corrosion in copper alloy piping, piping components, piping elements, and heat exchanger components exposed to closed
-cycle cooling water. The applicant stated that this item is not applicable because there are no corresponding components in the ESF systems exposed t o closed-cycle cooling water. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that Aging Management Review Results 3-277 the applicant's LRA does not have any AMR results that include copper piping, piping components, piping elements, or heat exchanger components exposed to closed
-cycle cooling water in the ESF systems. The staff also reviewed the UFSAR and confirmed that no in
-scope copper piping, piping components, piping elements, or heat exchanger components exposed to closed-cycle cooling water are present in the ESF systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.2.1, item 3.2.1
-32 addresses loss of material due to general corrosion in steel piping and ducting components and internal surfaces exposed internally to uncontrolled indoor air. The applicant stated that this line item is not applicable because the AMR methodology assumes internal surfaces are exposed to an air/gas
-wetted environment, which includes condensation, and as a result, item 3.2.1
-34 is credited for this component instead. The staff evaluated the applicant's claim and found it acceptable because the applicant has credited an alternate line item (item 3.2.1
-34) to manage this component group, which includes management for loss of material due to pitting and crevice corrosion, in addition to general corrosion.
LRA Table 3.2.1, item 3.2.1
-33 addresses loss of material due to general, pitting, and crevice corrosion in steel encapsulation components exposed internally to uncontrolled indoor air. The applicant stated that this line item is not applicable because there are no steel encapsulation components exposed to indoor air in the ESF systems. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant's LRA does not have any AMR results for the ESF systems that include steel encapsulation components exposed internally to uncontrolled indoor air. The staff also reviewed the applicant's UFSAR and confirmed that no in
-scope steel encapsulation components exposed internally to uncontrolled indoor air are present in the ESF system and, therefore, finds the applicant's determination acceptable.
LRA Table 3.2.1, item 3.2.1-35 addresses loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion and fouling for the internal surfaces of steel containment isolation piping and components exposed to raw water. The applicant stated that this item is not applicable because there are no corresponding components in the ESF systems exposed to raw water. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant's LRA does not have any AMR results that include corresponding components exposed to raw water in the ESF systems. The staff also reviewed the UFSAR and confirmed that no in
-scope steel containment isolation piping and components exposed to raw water are present in the ESF systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.2.1, item 3.2.1-36 addresses loss of material due to general, pitting, crevice, galvanic, and microbiologica lly-influenced corrosion and fouling for steel heat exchanger components exposed to raw water. The applicant stated that this item is not applicable because there are no corresponding components in the ESF systems exposed to raw water. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant's LRA does not have any AMR results that include corresponding components exposed to raw water in the ESF systems. The staff also reviewed the UFSAR and confirmed that no in
-scope steel heat exchanger components exposed to raw water are present in the ESF systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.2.1, item 3.2.1-37 addresses loss of material due to pitting, crevice, and microbiologically
-influenced corrosion for stainless steel piping, piping components, and piping elements exposed to raw water. The applicant stated that this item is not applicable because the corresponding components in the safety injection system are evaluated with the service Aging Management Review Results 3-278 water system in Table 3.4.1, item 3.4.1-33. The staff reviewed LRA Sections 2.3.2, 2.3.4, 3.2, and 3.4 and confirmed that the corresponding components exposed to raw water in the safety injection system were evaluated through item 3.4.1-33. The staff also reviewed the UFSAR and did not identify any other in
-scope stainless steel piping, piping components, or piping elements exposed to raw water in the ESF systems which were not evaluated in the LRA and, therefore, finds the applicant's determination acceptable.
LRA Table 3.2.1, item 3.2.1-38 addresses loss of material due to pitting, crevice, and microbiologically
-influenced corrosion and fouling for the internal surfaces of stainless steel containment isolation piping and components exposed to raw water. The applicant stated that this item is not applicable because there are no corresponding components in the ESF systems exposed to raw water. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant's LRA does not have any AMR results that include corresponding components exposed to raw water in the ESF systems. The staff also reviewed the UFSAR and confirmed that no in
-scope stainless steel containment isolation piping and components exposed to raw water are present in the ESF systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.2.1, item 3.2.1-39 addresses loss of material due to pitting, crevice, and microbiologically
-influenced corrosion and fouling for stainless steel heat exchanger components exposed to raw water. The applicant stated that this item is not applicable because there are no corresponding components in the ESF systems exposed to raw water. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant's LRA does not have any AMR results that include corresponding components exposed to raw water in the ESF systems. The staff also reviewed the UFSAR and confirmed that no in
-scope stainless steel heat exchanger components exposed to raw water are present in the ESF systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.2.1, item 3.2.1-40 addresses reduction of heat transfer due to fouling for steel and stainless steel heat exchanger tubes exposed to raw water. The applicant stated that this item is not applicable because there are no corresponding components in the ESF systems exposed to raw water. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant's LRA does not have any AMR results that include corresponding components exposed to raw water in the ESF systems. The staff also reviewed the UFSAR and confirmed that no in
-scope steel or stainless steel heat exchanger tubes exposed to raw water are present in the ESF systems and, therefore, finds the applicant's determination acceptable. LRA Table 3.2.1, item 3.2.1
-41 addresses copper alloy greater than 15 percent z i n c piping, piping components, piping elements, and heat exchanger components exposed to closed
-cycle cooling water. The GALL Report recommends the use of GALL 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 line item is not applicable because there are no ESF system components fabricated from copper alloy greater than 15 percent zinc and exposed to closed-cycle cooling water. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant's LRA does not have any AMR results for the ESF systems that include copper alloy greater than 15 percen t zinc piping, piping components, piping elements, and heat exchanger components exposed to closed
-cycle cooling water. The staff also reviewed the applicant's UFSAR and confirmed that no in
-scope copper alloy greater than 15 percent zinc piping, piping components, piping elements, and heat exchanger components exposed to closed-cycle cooling water are present in the ESF systems. Based on its review of the LRA, the staff confirmed that there are no in
-scope copper alloy greater than 15 percent zi nc piping, Aging Management Review Results 3-279 piping components, piping elements, and heat exchanger components exposed to closed
-cycle cooling water in the ESF systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.2.1, item 3.2.1
-42 addresses gray cast iron piping, piping components, and piping elements exposed to closed
-cycle cooling water. The applicant stated that this line item was not applicable. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant's LRA does not have any AMR results for the ESF systems that include gray cast iron piping, piping components, and piping elements exposed to closed
-cycle cooling water. The staff also noted that a search of the applicant's UFSAR did not find any evidence of gray cast iron piping, piping components, and piping elements in the ESF systems exposed to closed
-cycle cooling water. Based on its review of the LRA and UFSAR, the staff confirmed that there are no
 
in-scope gray cast iron piping, piping components, and piping elements exposed to soil in the ESF systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.2.1, item 3.2.1
-43 addresses gray cast iron piping, piping components, and piping elements exposed to soil. The GALL Report recommends the use of GALL 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 line item was not applicable because there are no ESF system piping, piping components, and piping elements fabricated from gray cast iron and exposed to soil. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant's LRA does not have any AMR results for the ESF systems that include gray cast iron piping, piping components, and piping elements exposed to soil. The staff also noted that a search of the applicant's UFSAR did not find any evidence of gray cast iron piping, piping components, and piping elements in the ESF systems exposed to soil. Based on its review of the LRA and UFSAR, the staff confirmed that there are no in
-scope gray cast iron piping, piping components, and piping elements exposed to soil in the ESF systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.2.1, item 3.2.1
-44 addresses gray cast iron motor coolers exposed to treated water. The GALL Report recommends the use of GALL 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 line item is not applicable because there are no ESF system components fabricated from and exposed to treated water. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant's LRA does not have any AMR results for the ESF systems that include gray cast iron motor coolers exposed to treated water. The staff also noted that a search of the applicant's UFSAR did not find any evidence of gray cast motor coolers in the ESF systems exposed to treated water. Based on its review of the LRA and the UFSAR, the staff confirmed that there are no in
-scope gray cast iron motor coolers exposed to treated water in the ESF systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.2.1, item 3.2.1
-46 addresses loss of material due to general, pitting, crevice, and boric acid corrosion in steel encapsulation components exposed internally to air with borated water leakage. The applicant stated that this line item is not applicable because there are no steel encapsulation components exposed to air with borated water leakage in the ESF systems. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant's LRA does not have any AMR results for the ESF systems that include steel encapsulation components exposed internally to air with borated water leakage. The staff also reviewed the applicant's UFSAR and confirmed that no in
-scope steel encapsulation components exposed internally to air with borated water leakage are present in the ESF systems and, therefore, finds the applicant's determination acceptable.
 
Aging Management Review Results 3-280 LRA Table 3.2.1, item 3.2.1
-47 addresses loss of fracture toughness due to thermal aging embrittlement in CASS piping, piping components, and piping elements exposed to treated water (borated or unborated) greater than 250
&deg; C (482&deg; F). The applicant stated that this line item is not applicable because there are no CASS piping, piping components, or piping elements subject to treated water greater than 250
&deg; C (482&deg; F) in the ESF systems. The staff reviewed the applicant's UFSAR Table 6.3-14 which states that valves in the emergency core cooling system (ECCS) are constructed of austenitic stainless steel. The staff reviewed the applicant's LRA drawings and determined that the only CASS components that could b e exposed to temperatures greater than 250&deg; C  (482&deg; F) are the safety injection cold leg check valves given that based on the size of the piping, it would not be constructed of cast materials and the safety injection cold leg check valves would prevent upstream components that could be constructed from cast austenitic materials from being exposed to temperatures greater than 250&deg; C (482&deg; F). The LRA and supplemental documents lack sufficient detail for the staff to determine if the safety injection cold leg check valves are constructed of CASS and if they are exposed to temperatures greater than 250
&deg; C (482&deg; F). By letter dated August 19, 2010, the staff issued RAI 3.2.1.47-01 requesting that the applicant state whether the safety injection cold leg check valves are constructed of CASS and if they are exposed to temperatures greater than 250&deg; C (482&deg; F). In its response dated September 7, 2010, the applicant stated that the safety injection cold leg check valves are constructed of CASS and exposed to temperatures greater than 250
&deg; C (482&deg; F), and the LRA should have included GALL Report item IV.C2
-6 in LRA Table 3.2.2-3 for this component type. The applicant also stated that: (1) it has revised the LRA to add the AMR line item to Table 3.2.2-3; (2) it has referenced Table 1, item 3.1.1
-55; and (3) the aging effect will be managed by the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program.
The staff finds the applicant's response acceptable because GALL AMP XI.M12, "Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)," states:
For pump casings and valve bodies, based on the assessment documented in the letter dated May 19, 2000, from Christopher Grimes, Nuclear Regulatory Commission (NRC), to Douglas Walters, Nuclear Energy Institute (NEI), screening for susceptibility to thermal aging is not required. The existing ASME Section XI inspection requirements, including the alternative requirements of ASME Code Case N-481 for pump casings, are adequate for all pump casings and valve bodies.
The staff's concern described in RAI 3.2.1.47-01 is resolved.
LRA Table 3.2.1, item 3.2.1
-51 addresses galvanized steel ducting externally exposed to controlled indoor air. The applicant stated that this line item is not applicable because the applicant does not have any galvanized steel ducting externally exposed to controlled indoor air in the ESF systems. The applicant also stated that there is no AERM or recommended AMP for this material and component combination. The staff notes that the GALL Report recommends that there is no AERM or AMP for this material and environment combination.
The staff, therefore, finds that the applicant's proposal that there is no AERM or AMP acceptable regardless of whether or not the material and environment combination exists in the ESF systems.
Aging Management Review Results 3-281 LRA Table 3.2.1, item 3.2.1
-54 addresses steel piping, piping components, and piping elements externally exposed to controlled indoor air. The applicant stated that this line item is not applicable because the applicant does not have any steel piping, piping components, and piping elements exposed to controlled indoor air in the ESF systems and all indoor air is assumed to be uncontrolled for the purposes of license renewal. The staff reviewed LRA Sections 2.3.3 and 3.2 and confirmed that the applicant's LRA does have AMR results for steel components exposed to indoor uncontrolled air and that those items are being managed by alternative line items applicable to indoor uncontrolled air. The staff finds the applicant's determination acceptable because uncontrolled air is a more aggressive environment than controlled air and the items are being managed by appropriate alternative line items.
LRA Table 3.2.1, item 3.2.1
-55 addresses steel and stainless steel piping, piping components, and piping elements in concrete. The applicant stated that this line item is not applicable because the applicant does not have any steel and stainless steel piping, piping components, and piping elements exposed to concrete in the ESF systems. The applicant also stated that there is no AERM or recommended AMP for this material and component combination. The staff notes that the GALL Report recommends that there is no AERM or AMP for this material and environment combination. The staff, therefore, finds that the applicant's proposal that there is no AERM or AMP acceptable regardless of whether or not the material and environment combination exists in the ESF systems.
3.2.2.1.2  Conclusion for AMRs Consistent with the GALL Report The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing the associated aging effects. On the basis of its review, the staff concludes that the AMR results, which the applicant claimed to be consistent with the GALL Report, are consistent with the GALL Report AMRs. Therefore, the staff concludes that the applicant has demonstrated that the aging effects for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.2.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation Is Recommended LRA Section 3.2.2.2 provides further evaluation of aging management as recommended by the GALL Report for the ESF components. The applicant provided information concerning how it will manage the following aging effects:
cumulative fatigue damage loss of material due to cladding breach loss of material due to pitting and crevice corrosion reduction of heat transfer due to fouling hardening and loss of strength due to elastomer degradation loss of material due to erosion Aging Management Review Results 3-282  loss of material due to general corrosion and fouling loss of material due to general, pitting, and crevice corrosion loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion  QA for aging management of nonsafety
-related components For component groups evaluated in the GALL Report for which the applicant claimed consistency with the GALL Report and for which further evaluation is recommended, the staff audited and reviewed the applicant's evaluations to determine whether they adequately address those issues. In addition, the staff reviewed the applicant's further evaluations against the criteria in SRP
-LR Secti on 3.2.2.2. The staff's review of the applicant's further evaluation follows. 3.2.2.2.1  Cumulative Fatigue Damage LRA Section 3.2.2.2.1 states fatigue is a TLAA as defined in 10 CFR 54.3. Furthermore, TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c). The applicant stated that the evaluation of metal fatigue as a TLAA for the residual heat removal and safety injection systems is discussed 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 fatigue of ESF components is a TLAA as defined in 10 CFR 54.3 and that 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 the staff's recommended acceptance criteria and review procedures for reviewing these TLAAs in SRP
-LR Section 4.3, "Metal Fatigue Analysis."  The staff also reviewed LRA Section 3.2.2.2.1 and the AMRs discussed in this Section against the staff's AMR items for evaluating cumulative fatigue damage in PWR ESF designs, as given in AMR item 1 of Table 2 of the GALL Report, Volume 1 and the AMR items in Section V of the GALL Report, Volume 2, Revision 1 that derive from this GALL Report, Volume 1 AMR item.
With regard to LRA Table 3.2.1, item 3.2.1
-1, the staff noted that GALL AMR item V.D1
-27 identifies cumulative fatigue damage as an applicable aging effect for steel and stainless steel piping, piping components, and piping elements in the ECCS and recommends that the TLAA on metal fatigue be used to manage this aging effect. The applicant included an applicable line item in LRA Tables 3.2.2-2 and 3.2.2
-3 for piping and fittings that received implicit fatigue analysis calculations in accordance with design code requirements for ASME C ode Section III Class 2 or 3 components or ANSI B31.1 components consistent with the recommendations in the SRP-LR. Based on its review, the staff finds the applicant's AMR analysis on cumulative fatigue damage of piping and fittings acceptable because it is consistent with the recommendations in SRP
-LR Section 3.2.2.2.1. The staff's evaluation of the TLAA analysis for the piping and fittings component is in SER Section 4.3.3. Based on the programs identified, the staff concludes that the applicant has 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 determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
Aging Management Review Results 3-283 3.2.2.2.2  Loss of Material Due to Cladding Breach LRA Section 3.2.2.2.2 addresses carbon steel pump casings with stainless steel cladding exposed to treated borated water. The GALL Report recommends use of a plant
-specific AMP to manage the loss of material due to cladding breach for this component group. The applicant stated that this line item is not applicable because there are no comparably constructed pump casings in the ESF systems. The applicant added that only Unit 2 has carbon steel pump casings with stainless steel cladding and these are evaluated in Table 3.3.1, items 3.3.1-35 and 3.3.1-91, as part of the chemical and volume control system in the auxiliary systems section. The staff reviewed LRA Sections 2.3.3 and 3.2 and confirmed that the applicant's LRA does not have any AMR results for the ESF systems that include carbon steel pump casings with
 
stainless steel cladding exposed to treated borated water. The staff reviewed the applicant's UFSAR, which indicates that the charging pumps fabricated of carbon steel with stainless steel cladding are only found in Unit 2 and are included in the auxiliary systems as part of the chemical and volume control system and, therefore, the staff finds the applicant's determination 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 criteria in SRP-LR Section 3.2.2.2.3.
  (1) LRA Section 3.2.2.2.3.1, associated with LRA Table 3.2.1, item 3.2.1-3, addresses loss of material due to pitting and crevice corrosion in stainless steel containment isolation piping, piping components, and piping elements exposed to treated water. The applicant stated that this item is not applicable because the related components are exposed to treated borated water, not treated water. The applicant also stated that the internal surfaces of stainless steel piping and piping components exposed to treated borated water in the ESF systems are evaluated with Table 3.2.1, item 3.2.1-49. The staff reviewed LRA Sections 2.3.2 and 3.2 and noted that LRA Table 3.3.2-1 for the containment spray system contained comparable components in a treated water environment, but these items were addressed in item 3.3.1-24, which is evaluated further in SER Section 3.3.2.2.10, item 2 for auxiliary systems. Otherwise, the staff confirmed that the applicant's LRA does not have any AMR results for the ESF systems that include stainless steel containment isolation piping components and piping elements exposed to treated water. In addition, the staff noted that the GALL Report does not recommend further evaluation for components associated with Table 3.2.1, item 3.2.1-49. The staff reviewed the applicant's UFSAR and, other than noted above for the containment spray system, confirmed that no in
-scope stainless steel containment isolation piping, piping components, and piping elements exposed to treated water are present in the ESF systems and, therefore, finds the applicant's determination acceptable.
  (2) LRA Section 3.2.2.2.3.2 refers to Table 3.2.1, item 3.2.1
-4 and addresses loss of material due to pitting and crevice corrosion in stainless steel piping, piping components, and piping elements exposed to soil. The applicant stated that this item is not applicable because the piping, piping components, and piping elements external surfaces in the containment spray system, residual heat removal system, and safety injection system are not exposed to soil because all of the stainless steel piping, piping components, and piping elements are inside the auxiliary building and containment structure. The applicant also stated that the refueling water storage tank in the safety injection system has a stainless steel bottom exposed to soil and the aging effect is managed by the Aging Management Review Results 3-284 Aboveground Non
-Steel Tanks Program. The staff reviewed the LRA AMR items and information in the UFSAR associated with Table 3.2.1, item 3.2.1
-4 and confirmed that there are no stainless steel piping, piping components, and piping elements exposed to soil in the ESF systems. Therefore, the staff finds the applicant's determination that LRA Table 3.2.1, item 3.2.1
-4 is not applicable acceptable.
  (3) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion and states that this aging effect is not applicable to Salem, which is a PWR.
SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice corrosion may occur in BWR stainless steel and aluminum piping, piping components, and piping elements exposed to treated water.
This line item is not applicable to Salem because Salem is a PWR. On this basis, the staff finds that the SRP-LR criteria do not apply to Salem.
  (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 stated that this item is not applicable because there are no stainless steel and copper alloy piping, piping components, and piping elements exposed to lubricating oil in the ESF systems. However, the applicant stated that the safety injection system pump lube oil coolers are titanium and are evaluated with the service water system, which is an ESF system. 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 the loss of material through examination of susceptible locations in titanium pump lube oil coolers exposed to lubricating oil in the safety injection 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 contaminant control should be verified 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 reviewed the UFSAR to verify that there are no stainless steel and copper alloy piping, piping components, and piping elements exposed to lubricating oil in the ESF systems at Salem. Instead, the applicant stated that titanium lube oil coolers are exposed to lubricating oil and are components in an ESF system (i.e., safety injection system).
The staff's evaluation of the applicant's Lubricating Oil Analysis and One
-Time Inspection programs is documented in SER Sections 3.0.3.2.12 and 3.0.3.1.11, Aging Management Review Results 3-285 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:  (1) the Lubricating Oil Analysis Program was determined to be consistent with the GALL Report, and (2) the applicant stated that the One
-Time Inspection Program will be used to examine titanium pump lube oil coolers to verify the effectiveness of the Lubricating Oil Analysis Program. This satisfies the acceptance criteria in SRP
-LR Section 3.2.2.2.3, item 4 and, therefore, the applicant's AMR is consistent with GALL Report items V.A
-21, V.D1-18, and V.D1
-24. Based on information in the UFSAR, the staff confirmed that the applicant's plant does not have stainless steel and copper alloy piping, piping components, and piping elements exposed to lubricating oil in the ESF systems. Therefore, the staff finds that this item is not applicable. Instead, titanium lube oil coolers are exposed to lubricating oil and are components in an ESF system (i.e., safety injection system). The staff reviewed this AMR and concludes that the applicant's programs meet SRP
-LR Section 3.2.2.2.3, item 4 criteria. For the line items that apply to LRA Section 3.2.2.2.3.4, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
  (5) LRA Section 3.2.2.2.3 Item 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 line item is not applicable because there are no partially encased stainless steel tanks with breached moisture barrier exposed to raw water in the ESF systems. The staff reviewed LRA Sections 2.3.2 and 3.2, and UFSAR and confirmed that no in
-scope partially encased stainless steel tanks exposed to raw water due to cracking of the perimeter seal from weathering are present in the ESF systems and, therefore, finds the applicant's determination acceptable.
  (6) LRA Section 3.2.2.2.3, item 6 is referenced by LRA Table 3.2.1, item 3.2.1-8 and addresses stainless steel piping, piping components, and piping elements exposed to wetted air and gas which are being managed for loss of material due to pitting and crevice corrosion by the Periodic Inspection Program. The applicant addressed the further evaluation criteria of the SRP
-LR by stating that the subject components exposed to the subject environment in the containment spray system will be managed by the Periodic Inspection Program, which manages the aging effects of components not covered by other AMPs. The applicant also stated that the Periodic Inspection Program includes visual inspections and volumetric examinations to assure that material degradation does not result in a loss of component intended function.
Based on a review of the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.2.2.2.3 criteria. For those line items that apply to LRA Section 3.2.2.2.3, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
Aging Management Review Results 3-286 3.2.2.2.4  Reduction of Heat Transfer Due to Fouling The staff reviewed LRA Section 3.2.2.2.4 against the criteria in SRP
-LR Secti on 3.2.2.2.4.
  (1) LRA Section 3.2.2.2.4.1, referenced by LRA Table 3.2.1, item 3.2.1
-9, addresses steel, stainless steel, and copper alloy 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 applicant stated that this item is not applicable to the ESF systems because there are no steel, stainless steel, and copper alloy heat exchanger tubes exposed to lubricating oil. However, the applicant stated that the safety injection system pump lube oil coolers are titanium and are evaluated with the service water system. 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 the loss of material through examination of susceptible locations in titanium pump lube oil coolers exposed to lubricating oil in the safety injection system. The staff reviewed LRA Section 3.2.2.2.4.1 against the criteria in SRP
-LR Section 3.2.2.2.4, item 1, which states that reduction of heat transfer due to fouling could occur for steel, stainless steel, and copper alloy heat exchanger tubes exposed t o lubricating oil. The SRP
-LR also states that the existing AMP relies on monitoring and control of lube oil chemistry to mitigate reduction of heat transfer due to fouling. The SRP-LR further states that control of lube oil chemistry may not always have been adequate to preclude fouling; therefore, the effectiveness of lube oil chemistry control should be verified to ensure that fouling does not occur. The SRP
-LR also states that the GALL Report recommends further evaluation of programs to verify the effectiveness of lube oil chemistry control for which a one
-time inspection of selected components at susceptible locations is an acceptable method to determine whether an aging effect is not occurring or an aging effect is progressing very slowly such that the component's intended function will be maintained during the period of extended operation.
The staff reviewed the UFSAR to verify that there are no steel, stainless steel, and copper alloy heat exchanger tubes exposed to lubricating oil in the ESF systems at Salem. Instead, the applicant stated that titanium lube oil coolers are exposed to lubricating oil and are components in an ESF system (i.e., safety injection system).
The staff's evaluation of the applicant's Lubricating Oil Analysis and One
-Time Inspection programs is documented in SER Sections 3.0.3.2.12 and 3.0.3.1.11, 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 verif y the effectiveness of the Lubricating Oil Analysis Program acceptable because:  (a) the Lubricating Oil Analysis Program was determined to be consistent with the GALL Report, and (b) the applicant stated that the One
-Time Inspection Program will be used to examine titanium pump lube oil coolers to verify the effectiveness of the Lubricating Oil Analysis Program. This satisfies the acceptance criteria in SRP
-LR Section 3.2.2.2.3.4 and, therefore, the applicant's AMR is consistent with the one under GALL Report items V.A-17, V.D1-12, V.A-12, V.D1-8, V.A-14, and V.D1
-10. Based on information in the UFSAR, the staff confirmed that the applicant's plant does not have steel, stainless steel, and copper alloy heat exchanger tubes exposed to lubricating oil in the ESF systems. Therefore, the staff finds that this item is not applicable. Instead, titanium lube oil coolers are exposed to lubricating oil and are Aging Management Review Results 3-287 components in an ESF system (i.e., safety injection system). The staff reviewed this AMR and concludes that the applicant's programs meet SRP
-LR Section 3.2.2.2.4, item 1 criteria. For the line items that apply to LRA Section 3.2.2.2.4.1, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
  (2) LRA Section 3.2.2.2.4, item 2 is referenced by LRA Table 3.2.1, item 3.2.1-10 and addresses stainless steel heat exchanger tubes exposed to a treated water environment, which are being managed for reduction of heat transfer due to fouling by the Water Chemistry 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 implemented for susceptible locations to verify the effectiveness of the Water Chemistry Program in the residual heat removal heat exchangers. The staff reviewed LRA Section 3.2.2.2.4, item 2 against the criteria in SRP
-LR Section 3.2.2.2.4, item 2, which states that reduction of heat transfer due to fouling could occur for stainless steel heat exchanger tubes exposed to treated water. The SRP-LR also states that the existing program relies on control of water chemistry to manage reduction of heat transfer due to fouling and that a one
-time inspection is an acceptable method to verify the effectiveness of the water chemistry controls.
The staff's evaluation of the applicant's Water Chemistry and One
-Time Inspection Program is documented in SER Sections 3.0.3.1.2 and 3.0.3.1.11, 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 above programs acceptable because the Water Chemistry Program provides for periodic sampling of treated water to maintain contaminants at acceptable limits to preclude loss of heat transfer due to fouling. In addition, the One
-Time Inspection Program will verify the effectiveness of the Water Chemistry Program by determining sample sizes based on materials, environments, aging mechanisms, and operating experience and by identifying inspection locations and examination techniques, including acceptance criteria, based on the aging effects for which the components are being examined.
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 line items that apply to LRA Section 3.2.2.2.4, item 2, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.2.2.2.5  Hardening and Loss of Strength Due to Elastomer Degradation LRA Section 3.2.2.2.5 addresses hardening and loss of strength due to elastomer degradation , stating that this aging effect is not applicable to Salem which is a PWR. SRP
-LR Section 3.2.2.2.5 states that hardening and loss of strength due to elastomer degradation may occur in elastomer seals and components of the BWR standby gas treatment system ductwork and filters exposed to uncontrolled indoor air. This item is not applicable to Salem because Salem is a PWR. On this basis, the staff finds that SRP
-LR 3.2.2.2.5 criteria do not apply to Salem. Based on the above, the staff concludes that SRP
-LR Section 3.2.2.2.5 criteria do not apply.
Aging Management Review Results 3-288 3.2.2.2.6  Loss of Material Due to Erosion LRA Section 3.2.2.2.6 refers to LRA Table 3.2.1, item 3.2.1-12 and addresses stainless steel orifices exposed to treated borated water, which are being managed for loss of material due to erosion by the Water Chemistry Program. The applicant addressed the further evaluation criteria of the SRP
-LR by stating that it will implement the Water Chemistry Program to manage this aging effect for the charging pump minimum
-flow orifice in the chemical and volume control system. The applicant also stated that the high
-pressure charging pumps are not used for normal charging flow, unless the positive displacement pump is out of service for maintenance, and added that the positive displacement pump does not have flow through the recirculation orifice. The applicant concluded that an additional inspection of the minimum
-flow recirculation orifice is not warranted.
The staff reviewed LRA Section 3.2.2.2.6 against the criteria in SRP
-LR Section 3.2.2.2.6, which states that loss of material due to erosion could occur in the stainless steel high-pressure safety injection (HPSI) pump minimum
-flow recirculation orifice exposed to treated borated water. The SRP-LR also states that the GALL Report recommends a plant
-specific AMP be evaluated for erosion of the orifice due to extended use of the centrifugal HPSI pump for normal charging and that acceptance criteria are described in Branch Technical Position RSLB
-1. In its review of components associated with item 3.2.1-12, the staff noted that the use of the Water Chemistry Program alone would not adequately manage this aging effect if the positive displacement pumps were out of service for extended periods of time. It was not clear to the staff how extensively the high
-pressure charging pumps in the chemical and volume control system have been used for normal charging, which could cause erosion of the minimum
-flow orifice.
During a conference call on July 22, 2010, the staff requested that the applicant provide additional information regarding the use of the associated pumps for normal charging. In its response to the RAI
, dated August 26, 2010, the applicant provided a supplement to its LRA, stating that it had incorrectly included the aging mechanism of loss of material due to erosion for the restricting orifices in the safety injections and chemical and volume control systems. The applicant revised LRA Section 3.2.2.2.6 to state that LRA Table 3.2.1, item 3.2.1-12 did not apply to Salem and reiterated that an inspection of the orifices is not warranted to manage erosion on these restricting orifices because they only experience limited flow every quarter, during surveillance tests. The staff finds the applicant's revision to LRA Section 3.2.2.2.6 in the LRA supplement acceptable because the limited usage of the restricting orifices will not subject them to the aging effect described in Licensee Event Report (LER) 50
-275/94-023, as referenced in the GALL Report for this item.
3.2.2.2.7  Loss of Material Due to General Corrosion and Fouling The staff reviewed LRA Section 3.2.2.2.7 against the criteria in SRP
-LR Section 3.2.2.2.7.
LRA Section 3.2.2.2.7 addresses loss of material due to general corrosion and fouling and states that this aging effect is not applicable to Salem which is a PWR.
SRP-LR Section 3.2.2.2.7 states that loss of material due to general corrosion and fouling may occur on steel drywell and the suppression chamber spray system nozzle and flow orifice internal surfaces exposed to uncontrolled indoor air and may cause plugging of the spray nozzles and flow orifices.
 
Aging Management Review Results 3-289 This item applies to BWR steel drywell and the suppression chamber spray system and is therefore not applicable to Salem because it is a PWR. On this basis, the staff finds that that SRP-LR Section 3.2.2.2.7 criteria do not apply to Salem.
Based on the above, the staff concludes that SRP
-LR Section 3.2.2.2.7 criteria do not apply.
3.2.2.2.8  Loss of Material Due to General, Pitting, and Crevice Corrosion The staff reviewed LRA Section 3.2.2.2.8 against the criteria in SRP
-LR Section 3.2.2.2.8.
  (1) LRA Section 3.2.2.2.8 addresses loss of material due to general, pitting, and crevice corrosion and states that this aging effect is not applicable to Salem, which is a PWR.
SRP-LR Section 3.2.2.2.8 states that loss of material due to general, pitting, and crevice corrosion may occur in BWR steel piping, piping components, and piping elements exposed to treated water.
This line item is not applicable to Salem because Salem is a PWR. On this basis, the staff finds that the SRP
-LR criteria do not apply.
  (2) LRA Section 3.2.2.2.8, item 2, associated with LRA Table 3.2.1, item 3.2.1
-15, addresses loss of material due to general, pitting and crevice corrosion for the interna l
surfaces of steel containment isolation piping, piping components, and piping elements exposed to treated water. The applicant stated that this line item is not applicable because there is no steel containment isolation piping, piping components, and piping elements exposed to treated water in the ESF systems. The staff reviewed LRA Sections 2.3.2 and 3.2, and the UFSAR and confirmed that no in
-scope internal surfaces of steel containment isolation piping, piping components, and piping elements exposed to treated water are present in the ESF systems and, therefore, finds the applicant's determination acceptable.
  (3) LRA Section 3.2.2.2.8, item 3, associated with LRA Table 3.2.1, item 3.2.1
-16, addresses loss of material due to general, pitting and crevice corrosion for steel piping, piping components, and piping elements exposed to lubricating oil. The applicant stated that this line item is not applicable because there is no steel piping, piping components, and piping elements exposed to lubricating oil in the ESF systems. The staff reviewed LRA Sections 2.3.2 and 3.2, and the UFSAR and confirmed that no in
-scope steel piping, piping components, and piping elements exposed to lubricating oil are present in the ESF systems and, therefore, finds the applicant's determination acceptable.
3.2.2.2.9  Loss of Material Due to General, Pitting, Crevice, and Microbiologically
-Influenced Corrosion LRA Section 3.2.2.2.9 refers to Table 3.2.1, item 3.2.1
-17 and addresses loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion in steel piping, piping components, and piping elements, with or without coating or wrapping, buried in soil. The applicant stated that this item is not applicable because there are no steel piping, piping components, and piping elements buried in soil in the ESF systems. The staff reviewed the LRA AMR items and information in the UFSAR associated with Table 3.2.1, item 3.2.1
-17 and confirmed that there are no steel piping, piping components, and piping elements exposed to soil in the ESF systems. Therefore, the staff finds the applicant's determination that LRA Table 3.2.1, item 3.2.1
-17 is not applicable acceptable.
 
Aging Management Review Results 3-290 3.2.2.2.10 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.
3.2.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report In LRA Tables 3.2.2
-1 through 3.2.2
-3, 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 3.2.2
-1 through 3.2.2
-3, the applicant indicated, via Notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report. The applicant provided further information concerning how the aging effects will be managed. Specifically, Note F indicates that the material for the AMR line item component is not evaluated in the GALL Report. Note G indicates that the environment for the AMR line item component and material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR line item component, material, and environment combination is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the line item component, material, and environment combination is not applicable. Note J indicates that neither the component nor the material and environment combination for the line item is evaluated in the GALL Report.
For component type, material, and environment combinations not evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine whether the applicant had demonstrated that the aging effects will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation. The staff's evaluation is discussed in the following sections.
3.2.2.3.1  Engineered Safety Features
-Containment Spray System
-Summary of Aging Management Evaluation
-LRA Table 3.2.2
-1 The staff reviewed LRA Table 3.2.2
-1, which summarizes the results of AMR evaluations for the containment spray system component groups.
The staff's review did not find any line items indicating plant
-specific Notes F through J whereby the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report.
The staff's evaluation of the line items with Notes A through E is documented in SER Section 3.2.2.1. 3.2.2.3.2  Engineered Safety Features
-Residual Heat Removal System
-Summary of Aging Management Evaluation
-LRA Table 3.2.2
-2 The staff reviewed LRA Table 3 2.2-2, which summarizes the results of AMR evaluations for the residual heat removal system component groups.
The staff's review did not find any line items indicating plant
-specific Notes F through J whereby the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report.
 
Aging Management Review Results 3-291 The staff's evaluation of the line items with Notes A through E is documented in SER Section 3.2.2.1. 3.2.2.3.3  Engineered Safety Features
-Safety Injection System
-Summary of Aging Management Evaluation
-LRA Table 3.2.2-3 The staff reviewed LRA Table 3.2.2
-3, which summarizes the results of AMR evaluations for the safety injection system component groups.
In LRA Table 3.2.2-3, the applicant stated that stainless steel tanks exposed to soil are being managed for loss of material due to pitting, crevice, and microbiologically
-influenced by the Aboveground Non
-Steel Tanks Program.
The AMR item cites generic note G, indicating that the environment is not evaluated in the GALL Report for this material and component combination.
The staff reviewed all AMR result line items in the GALL Report where the material is stainless steel and the aging effect/mechanism is loss of material due to pitting, crevice, and microbiologically
-influenced and confirmed that for this environment, there are no entries in the GALL Report for this component and material.
The staff's evaluation of the applicant's Aboveground Non
-Steel Tanks Program, is documented in SER Section 3.0.3.3.3.
The staff finds the applicant's proposal to manage aging using the Aboveground Non
-Steel Tanks Program acceptable because it requires periodic visual inspections of the accessible tank outer surface and wall
-thickness measurements of the inaccessible tank bottom external surface by ultrasonic testing and the acceptance criteria is based on industry codes and the original design parameters of the tanks.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
====3.2.3 Conclusion====
The staff concludes that the applicant has provided sufficient information to demonstrate that the effects of aging for the ESF system components within the scope of license renewal and subject to an AMR will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3).
3.3  Aging Management of Auxiliary Systems This Section of the SER documents the staff's review of the applicant's AMR results for the auxiliary systems components and component groups of the:
auxiliary building ventilation system chemical and volume control system
 
Aging Management Review Results 3-292  chilled water system circulating water system component cooling system compressed air system containment ventilation system  control area ventilation system cranes and hoists demineralized water system emergency diesel generators and auxiliaries system fire protection system fresh water system fuel handling and fuel storage system fuel handling ventilation system  fuel oil system heating water and heating steam system nonradioactive drain system radiation monitoring system radioactive drain system radwaste system sampling system service water system service water ventilation system spent fuel cooling system switchgear and penetration area ventilation system 3.3.1  Summary of Technical Information in the Application LRA Section 3.3 provides AMR results for the auxiliary systems components and component groups. LRA Table 3.3.1, "Summary of Aging Management Programs for Auxiliary Systems," is a summary comparison of the applicant's AMRs with those evaluated in the GALL Report for the auxiliary systems 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 whether the applicant provided sufficient information to demonstrate that the effects of aging for auxiliary systems components within the scope of license renewal and subject to an AMR will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
The staff conducted an onsite audit of AMPs to ensure the applicant's claim that certain AMPs were consistent with the GALL Report. The purpose of this audit was to examine the applicant's Aging Management Review Results 3-293 AMPs and related documentation and to verify the applicant's claim of consistency with the corresponding GALL Report AMPs. The staff did not repeat its review of the matters described in the GALL Report. The staff's evaluations of the AMPs are documented in SER Section 3.0.3. The staff reviewed the AMRs to confirm the applicant's claim that certain identified AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant had identified the appropriate GALL Report AMRs. Details of the staff's evaluation are discussed in SER Section 3.3.2.1 and 3.3.2.2.
The staff also reviewed the AMRs not consistent with or not addressed in the GALL Report. The review evaluated whether all plausible aging effects were identified and whether the aging effects listed were appropriate for the combination of materials and environments specified. Details of the staff's evaluation are discussed in SER Section 3.3.2.3. For components which the applicant claimed were not applicable or required no aging management, the staff reviewed the AMR line items and the plant's operating experience to verify the applicant's claims.
Table 3.3-1 summarizes the staff's evaluation of components, aging effects or mechanisms, and AMPs listed in LRA Section 3.3 and addressed in the GALL Report.
Table  3.3-1  Staff Evaluation for Auxiliary Systems Components in the GALL Report Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel cranes
- structural girders exposed to air
- indoor uncontrolled (external)
(3.3.1-1) Cumulative fatigue damage TLAA to be evaluated for structural girders of cranes. See SRP-LR Section 4.7 for generic guidance for meeting the requirements of 10 CFR 54.21(c)(1).
Yes TLAA Fatigue is a TLAA (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 Fatigue is a TLAA (see SER Section 3.3.2.2.1) Stainless steel heat exchanger tubes exposed to treated water (3.3.1-3) Reduction of heat transfer due to fouling Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to Salem (see SER Section 3.3.2.2.2)
 
Aging Management Review Results 3-294 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel piping, piping components, and piping elements exposed to sodium pentaborate solution
> 60 &deg;C (140 &deg;F) (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(1))
Stainless steel and stainless clad steel heat exchanger components exposed to treated water
> 60 &deg;C (140 &deg;F) (3.3.1-5) Cracking due to SCC A plant-specific AMP is to be evaluated.
Yes Not applicable Not applicable to Salem (see SER Section 3.3.2.2.3(2))
Stainless steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust (3.3.1-6) Cracking due to SCC A plant-specific AMP is to be evaluated.
Yes Periodic Inspection Consistent with the GALL Report (see SER Section 3.3.2.2.3(3))
Stainless steel
 
non-regenerative heat exchanger components exposed to treated borated water > 60 &deg;C (140 &deg;F) (3.3.1-7) Cracking due to SCC and cyclic 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 ECT of tubes.
Yes Water Chemistry Consistent with the GALL Report (see SER Section 3.3.2.2.4(1))
Stainless steel regenerative heat exchanger components exposed to treated borated water > 60 &deg;C (140 &deg;F) (3.3.1-8) Cracking due to SCC and cyclic 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 Consistent with the GALL Report (see SER Section 3.3.2.2.4(2))
 
Aging Management Review Results 3-295 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 high-pressure pump casing in PWR chemical and volume control system (3.3.1-9) Cracking due to SCC and cyclic loading Water Chemistry and a plant-specific verification program.
The AMP is to be augmented by verifying the absence of cracking due to SCC and cyclic loading. A plant-specific AMP is to be evaluated.
Yes Water Chemistry and One-Time Inspection Consistent with the GALL Report (see SER Section 3.3.2.2.4(3))
High-strength steel closure bolting exposed to air with steam or water leakage. (3.3.1-10) Cracking due to SCC 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 Salem (see SER Section 3.3.2.2.4(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 Periodic Inspection Consistent with the GALL Report (see SER Section 3.3.2.2.5(1))
Elastomer lining exposed to treated water or treated borated water (3.3.1-12) Hardening and
 
loss of strength due to elastomer degradation A plant-specific AMP is to be evaluated.
Yes Not applicable Not applicable to Salem (see SER Section 3.3.2.2.5(2))
Boral, boron steel spent fuel storage racks neutron-absorbing sheets exposed to treated water o r treated borated water (3.3.1-13) Reduction of neutron- absorbing capacity and loss of material due to general corrosion A plant-specific AMP is to be evaluated.
Yes Boral Monitoring and Water Chemistry Consistent with the GALL Report (see SER Section 3.3.2.2.6) Steel piping, piping components, 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 One-Time Inspection and Lubricating Oi l Analysis Consistent with the GALL Report (see SER Section 3.3.2.2.7(1))
Steel RCP 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 Oi l Analysis and One-Time Inspection Yes One-Time Inspection and Lubricating Oil Analysis Consistent with the GALL Report (see SER Section 3.3.2.2.7(1))
 
Aging Management Review Results 3-296 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 RCP 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 One-Time Inspection and Lubricating Oil Analysis Consistent with the GALL Report (see SER Section 3.3.2.2.7(1)) Steel piping, piping components, and piping elements exposed to treated water (3.3.1-17) Loss of material due to general, pitting, and crevice corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (see SER Sectio n 3.3.2.2.7(2))
Stainless steel and steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust (3.3.1-18) Loss of material/general (steel only), pitting, and crevice corrosion A plant-specific AMP is to be evaluat ed. Yes Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components and Periodic Inspection Consistent with the GALL Report (see SER Section 3.3.2.2.7(3))
Steel (with or without coating or wrapping) piping, piping components, and piping elements exposed to soil (3.3.1-19) Loss of material due to general, pitting, crevice, and microbiologically
 
-influenced corrosion Buried Piping and Tanks Surveillance or Buried Piping and Tanks Inspection No    Yes Buried Piping Inspection; Aboveground Steel Tanks; Buried Non-Steel Piping Inspection; RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants; and Structures Monitoring Consistent with the GALL Report (see SER Section 3.3.2.2.8)
Steel piping, piping components, piping elements, and tanks exposed to fuel oil (3.3.1-20) Loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion and fouling Fuel Oil Chemistry and One-Time Inspection Yes One-Time Inspection and Fuel Oil Chemistry Consistent with the GALL Report (see SER Section 3.3.2.2.9(1))
Steel heat exchanger components exposed to lubricating oil (3.3.1-21) Loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion and fouling Lubricating Oil Analysis and One-Time Inspection Yes Not applicable Not applicable to Salem (see SER Section 3.3.2.2.9(2))
 
Aging Management Review Results 3-297 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel 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 Salem (see SER Section 3.3.2.2.10(1))
Stainless steel and steel with stainless steel cladding heat exchanger components exposed to treated water (3.3.1-23) Loss of material due to pitting and crevice corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (see SER Section 3.3.2.2.10(2))
Stainless steel and aluminum piping, piping components, and piping elements exposed to treated water (3.3.1-24) Loss of material due to pitting and crevice corrosion Water Chemistry and One-Time Inspection Yes Water Chemistry and One-Time Inspection Consistent with the GALL Report (see SER Section 3.3.2.2.10(2))
Copper alloy 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 Periodic Inspection Consistent with the GALL Report (see SER Section 3.3.2.2.10(3))
Copper alloy piping, piping components, and piping elements exposed to lubricating oil (3.3.1-26) Loss of material due to pitting and crevice corrosion Lubricating Oil Analysis and One-Time Inspection Yes One-Time Inspection and Lubricating Oil Analysis Consistent with the GALL Report (see SER Section 3.3.2.2.10(4))
Stainless steel HVAC ducting and aluminum HVAC piping, piping components, and
 
piping elements exposed to condensation (3.3.1-27) Loss of material due to pitting and crevice corrosion A plant-specific AMP is to be evaluated.
Yes Periodic Inspection and Fire Protection Consistent with the GALL Report (see SER Section 3.3.2.2.10(5))
Copper alloy fire protection piping, piping components, and piping elements exposed to condensation (internal)
(3.3.1-28) Loss of material due to pitting and crevice corrosion A plant-specific AMP is to be evaluated.
Yes Periodic Inspection, Compressed Air Monitoring, Fire Protection, and Fire Water System Consistent with the GALL Report (see SER Section 3.3.2.2.10(6))
 
Aging Management Review Results 3-298 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel piping, piping components, and piping elements exposed to soil (3.3.1-29) Loss of material due to pitting and crevice corrosi on A plant-specific AMP is to be evaluated.
Yes Not applicable Not applicable to Salem (see SER Section 3.3.2.2.10(7))
Stainless steel piping, piping components, and piping elements exposed to sodium pentaborate solution (3.3.1-30) Loss of material due to pitting and crevice corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (see SER Section 3.3.2.2.10(8))
Copper alloy piping, piping components, and piping elements exposed to treated water (3.3.1-31) Loss of material due to pitting, crevice, and galvanic corrosion Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (see SER Section 3.3.2.2.11)
Stainless steel, aluminum, and copper alloy piping, piping components, and piping elements exposed to fuel oil (3.3.1-32) Loss of material due to pitting, crevice, and microbiologically
 
-influenced corrosion Fuel Oil Chemistry and One-Time Inspection Yes One-Time Inspection and Fuel Oil Chemistry Consistent with the GALL Report (see SER Section 3.3.2.2.12(1))
Stainless steel piping, piping components, and piping elements exposed to lubricating oil (3.3.1-33) Loss of material due to pitting, crevice, and microbiologically
-influenced corrosion Lubricating Oil Analysis and One-Time Inspection Yes One-Time Inspection and Lubricating Oil Analysis Consistent with the GALL Report (see SER Section 3.3.2.2.12(2))
Elastomer seals and components exposed to air - indoor uncontrolled (internal or external)
(3.3.1-34) Loss of material due to wear A plant-specific AMP is to be evaluated.
Yes Not applicable Not applicable to Salem (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 One-Time Inspection Consistent with the GALL Report (see SER Section 3.3.2.2.14)
Boraflex spent fuel storage racks neutron-absorbing sheets exposed to treated water (3.3.1-36) Reduction of neutron-absorbing capacity due to boraflex degradation Boraflex Monitoring No Not applicable Not applicable to PWRs (see SER Section 3.3.2.1.1)
 
Aging Management Review Results 3-299 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel piping, piping components, and piping elements exposed to treated water > 60 &deg;C (140 &deg;F) (3.3.1-37) Cracking due to SCC 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 > 60 &deg;C (140 &deg;F) (3.3.1-38) Cracking due to SCC BWR SCC and Water Chemistry No Not applicable Not applicable to PWRs (see SER Section 3.3.2.1.1)
Stainless steel BWR spent fuel storage racks exposed to treated water >
60 &deg;C (140 &deg;F) (3.3.1-39) Cracking due to 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 crevic e corrosion Aboveground Steel Tanks No Aboveground Steel Tanks Consistent with the GALL Report 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 Salem (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 Salem (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, External Surfaces Monitoring, and Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Consistent with the GALL Report (see SER Section 3.3.2.1.3)
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 Salem (see SER Section 3.3.2.1.1)
Aging Management Review Results 3-300 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel 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; Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems; Structures Monitoring; and ASME Section XI, SubSection IWF Consistent with the GALL Repor t (see SER Section 3.3.2.1.4)
Stainless steel and stainless steel clad piping, piping components, piping elements, and heat exchanger components exposed to closed-cycle cooling  water > 60 &deg;C (140 &deg;F) (3.3.1-46) Cracking due to SCC Closed-Cycle Cooling Water System No Closed-Cycle Cooling Water System Consistent with the GALL Report Steel piping, piping components, piping elements, tanks, and heat exchanger components exposed to closed-cycle cooling water (3.3.1-47) Loss of material due to general, pitting, and crevice corrosion Closed-Cycle Cooling Water System No Closed-Cycle Cooling Water System Consistent with the 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 the GALL Report 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 Salem (see SER Section 3.3.2.1.1)
Aging Management Review Results 3-301 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel 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 the GALL Report (see SER Section 3.3.2.1.5)
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 the 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 Syste m Consistent with the 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 Not applicable Not applicable to Salem (see SER Section 3.3.2.1.1) 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 Compressed Air Monitoring, Periodic Inspection, and Fire Protection Consistent with the GALL Report (see SER Section 3.3.2.1.6)
Steel ducting closure bolting exposed to air
- indoor uncontrolled (external)
(3.3.1-55) Loss of material due to genera l corrosion External Surfaces Monitoring No External Surfaces Monitoring Consistent with the GALL Report Steel HVAC ducting and components external surfaces exposed to air
- indoor uncontrolled (external)
(3.3.1-56) Loss of material due to general corrosion External Surfaces Monitoring No External Surfaces Monitoring Consistent with the GALL Report
 
Aging Management Review Results 3-302 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation 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, Fire Protection, and Fire Water System Consistent with the GALL Report (see SER Section 3.3.2.1.7)
Steel external surfaces exposed to air - indoor uncontrolled (external), air
- outdoor (external),
and condensation (external)
(3.3.1-58) Loss of material due to general corrosion External Surfaces Monitoring No External Surfaces Monitoring, Fire Protection, Fire Water System, and Structures Monitoring Consistent with the GALL Report (see SER Section 3.3.2.1.7) 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, Fire Protection, and Fire Water System Consistent with the GALL Report (see SER Section 3.3.2.1.8)
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 corrosio n External Surfaces Monitoring No External Surfaces Monitoring, Inspection of Overhead Heavy Load and Light Load (Related to Refueling Handling) Systems, Fire Protection, and Fire Water System Consistent with the GALL Report (see SER Section 3.3.2.1.8)
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; Structures Monitoring; and RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Consistent with the GALL Report (see SER Section 3.5.2.1-4) 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 Salem (see SER Section 3.3.2.1.1)
Aging Management Review Results 3-303 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel fire rated doors exposed to air
- outdoor or air - indoor uncontrolled (3.3.1-63) Loss of material due to wear Fire Protection No Fire Protection Consistent with the GALL Report 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 Not applicable Not applicable to
 
Salem (see SER Section 3.3.2.1.1) 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 No Not applicable Not applicable to Salem (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 No Fire Protection and Structures Monitoring Consistent with the GALL Report 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 No Fire Protection and Structures Monitoring Consistent with the GALL Report Steel piping, piping components, and piping elements exposed to raw water (3.3.1-68) Loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion and fouling Fire Water System No Fire Water System and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Consistent with the GALL Report (see SER Section 3.3.2.1.9 and 3.3.2.1-12) 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 Not applicable Not applicable to Salem (see SER Section 3.3.2.1.1) Copper alloy piping, piping components, and piping elements exposed to raw water (3.3.1-70) Loss of material due to pitting, crevice, and microbiologically
-influenced corrosion and fouling Fire Water System No Fire Water System and Periodic Inspection Consistent with the GALL Report (see SER Section 3.3.2.1.9)
 
Aging Management Review Results 3-304 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation 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 Inspection of Internal Surfaces in Miscellaneous Piping and Ductin g Components, Compressed Air Monitoring, Fire Protection, and Fire Water System Consistent with the GALL Report (see SER Section 3.3.2.1-10) Steel HVAC ducting and components internal surfaces exposed to condensation (internal)
(3.3.1-72) Loss of material due to general, pitting, crevice, and (for drip pans and drain lines) microbiologically
-influenced corrosion Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components No Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components and Fire Protection Consistent with the GALL Report (see SER Section 3.3.2.1.11)
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 Consistent with the GALL Report Steel cranes
- rails exposed to air
- indoor uncontrolled (external)
(3.3.1-74) Loss of material due to wear Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems No Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Consistent with the GALL Report Elastomer seals and components exposed to raw water (3.3.1-75) Hardening and loss of strength due to elastomer degradation; loss of material due to erosion Open-Cycle Cooling Water System No Open-Cycle Cooling Water System and
 
RG 1.1.27, Inspection of Water-Control Structures Associated with Nuclear Power Plants Consistent with the GALL Report (see SER Section 3.5.2.1.4)
Steel piping, piping components, and piping elements (without lining/ coating or with degraded lining/coating) exposed to raw water (3.3.1-76) Loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion, fouling, and lining/coating degradation Open-Cycle Cooling Water System No Open-Cycle Cooling Water System Consistent with the GALL Report Aging Management Review Results 3-305 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel heat exchanger components exposed to raw water (3.3.1-77) Loss of material due to general, pitting, crevice, galvanic, and microbiologically
 
-influenced corrosion and fouling Open-Cycle Cooling Water System No Open-Cycle Cooling Water System, Fire Water System, and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Consistent with the GALL Report (see SER Section 3.3.2.1.12)
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 Not applicable Not applicable to Salem (see SER Section 3.3.2.1.1)
Stainless steel piping, piping components, and piping element s 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 Not applicable Not applicable to Salem (see SER Section 3.3.2.1.1) Stainless steel and copper alloy piping, piping components, and piping elements exposed to raw water (3.3.1-80) Loss of material due to pitting, crevice, and microbiologically
-influenced corrosion Open-Cycle Cooling Water System No Periodic Inspection; Structures Monitoring; and RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Consistent with the GALL Report (see SER Section 3.3.2.1.13 and 3.5.2.1.5)
Copper alloy piping, piping components, and piping elements, exposed to raw water (3.3.1-81) Loss of material due to pitting, crevice, and microbiologically
-influenced corrosion and fouling Open-Cycle Cooling Water System No Open-Cycle Cooling Water System and Periodic Inspection Consistent with the GALL Report (see SER Section 3.3.2.1-14) Copper alloy heat exchanger components exposed to raw water (3.3.1-82) Loss of material due to pitting, crevice, galvanic, and microbiologically
-influenced corrosion and fouling Open-Cycle Cooling Water System No Open-Cycle Cooling Water System Consistent with the 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 Open-Cycle Cooling Water System Consistent with the GALL Report
 
Aging Management Review Results 3-306 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Copper alloy
> 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 the 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 the 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 No Not applicable Not applicable to Salem (see SER Section xxxxx) Boraflex spent fuel storage racks neutron-absorbing sheets exposed to treated borated water (3.3.1-87) Reduction of neutron-absorbing capacity due to boraflex degradation Boraflex Monitoring No Not applicable Not applicable to Salem (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 Boric Acid Corrosion Consistent with the GALL Report)
Steel bolting and external surfaces exposed to air with borated water leakage (3.3.1-89) Loss of material due to boric acid corrosion Boric Acid Corrosion No Boric Acid Corrosion Consistent with the GALL Report
 
Aging Management Review Results 3-307 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Stainless steel and steel with stainless steel cladding piping, piping components, piping elements, tanks, and fuel storage racks exposed to treated borated water
> 60 &deg;C (140 &deg;F) (3.3.1-90) Cracking due to SCC Water Chemistry No Water Chemistry Consistent with the 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 ASME Section XI, SubSection IWF Consistent with the GALL Report Galvanized steel piping, piping components, and piping elements exposed to air
- indoor uncontrolled (3.3.1-92) None None NA None Consistent with the 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 NA None Consistent with the 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 NA None Consistent with the GALL Report Steel and aluminum piping, piping components, and piping elements exposed to air
- indoor controlled (external)
(3.3.1-95) None None NA Not applicable Not applicable to Salem (see SER Section 3.3.2.1.1)
Aging Management Review Results 3-308 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel and stainless steel piping, piping components, and piping elements in concrete (3.3.1-96) None None NA None Consistent with the GALL Report  Steel, stainless steel, aluminum, and copper alloy piping, piping components, and piping elements exposed to gas (3.3.1-97) None None NA None Consistent with the GALL Report Steel, stainless steel, and copper alloy piping, piping components, and piping elements exposed to dried air (3.3.1-98) None None NA Compressed Air Monitoring (see SER Section 3.3.2.1.15)
Stainless steel and copper alloy
< 15% Zn piping, piping components, and piping elements exposed to air with borated water leakage (3.3.1-99) None None NA None Consistent with the GALL Report The staff's review of the auxiliary systems component groups followed several approaches. One approach, documented in SER Section 3.3.2.1, discusses the staff's review of AMR results for components the applicant indicated are consistent with the GALL Report and require no further evaluation. Another approach, documented in SER Section 3.3.2.2, discusses the staff's review of AMR results for components the applicant indicated are consistent with the GALL Report and for which further evaluation is recommended. A third approach, documented in SER Section 3.3.2.3, discusses the staff's review of AMR results for components the applicant indicated are not consistent with or not addressed in the GALL Report. The staff's review of AMPs credited to manage or monitor aging effects of the auxiliary systems components is documented in SER Section 3.0.3. 3.3.2.1  AMR Results That Are 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 Non
-Steel Tanks Aboveground Steel Tanks
 
Aging Management Review Results 3-309  ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Bolting Integrity Boral Monitoring Program Boric Acid Corrosion Buried Non
-Steel Piping Inspection Buried Piping Inspection  Closed-Cycle Cooling Water System Compressed Air Monitoring External Surfaces Monitoring Fire Protection Fire Water System Flow Accelerated Corrosion Fuel Oil Chemistry Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems  Lubricating Oil Analysis One-Time Inspection One-Time Inspection of ASME Code Class 1 Small-Bore Piping Open-Cycle Cooling Water System Periodic Inspection Selective Leaching of Materials Structures Monitoring Program Water Chemistry LRA Tables 3.3.2-1 through 3.3.2
-26 summarize AMRs for the auxiliary systems components and indicate AMRs claimed to be consistent with the GALL Repor
: t.
Aging Management Review Results 3-310 For component groups evaluated in the GALL Report for which the applicant had claimed consistency and for which the GALL Report does not recommend further evaluation, the staff performed an audit and review to determine whether the plant
-specific components in these GALL Report component groups were bounded by the GALL Report evaluation.
The applicant provided a note for each AMR line item. The notes describe how the information in the tables aligns with the information in the GALL Report. The staff audited those AMRs with notes A through E, which indicate how the AMR was consistent with the GALL Report.
Note A indicates that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. The staff audited these line items to verify consistency with the GALL Report and the validity of the AMR for the site
-specific conditions.
Note B indicates that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report and confirmed 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 condition
: s. Note C indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the AMP identified by the GALL Report. This note indicates that the applicant was unable to find a listing of some system components in the GALL Report; however, the applicant identified a different component in the GALL Report that had the same material, environment, aging effect, and AMP as the component under review. The staff audited these line items to verify consistency with the GALL Report. The staff also determined whether the AMR line item of the different component applied to the component under review and whether the AMR was valid for the site-specific conditions.
Note D indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report and confirmed whether the AMR line item of the different component was applicable to the component under review. The staff confirmed whether it had reviewed and accepted the exceptions to the GALL Report AMPs. It also determined whether the AMP identified by the applicant was consistent with the AMP identified in the GALL Report and whether the AMR was valid for the site
-specific conditions.
Note E indicates that the AMR line item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited. The staff audited these line items to verify consistency with the GALL Report and determined whether the identified AMP would manage the aging effect consistent with the AMP identified in the GALL Report and whether the AMR was valid for the site
-specific conditions.
The staff notes that in LRA Tables 3.3.2-2, 3.3.2-3, 3.3.2-5, 3.3.2-6, 3.3.2-10, 3.3.2-11, 3.3.2-12, 3.3.2-16, 3.3.2-17, 3.3.2-21, 3.3.2-22, and 3.3.2
-25, there are multiple tank line items exposed to material and environment combinations including carbon steel exposed to closed
-cycle cooling water, treated water, raw water, lube oil, and fuel oil; stainless steel exposed to treated Aging Management Review Results 3-311 borated water and raw water; carbon or low
-alloy steel with stainless steel cladding exposed to treated borated water; aluminum exposed to treated water; and gray cast iron exposed to raw water. The staff also notes that the LRA does not have a line item for the tank material exposed to an air or wetted gas internal environment as would occur when the tank is partially full. The staff further notes that with the exception of some line items in LRA Tables 3.3.2-2, 3.3.2-21, and 3.3.2-25 (see following discussion), in each instance the LRA line items manage the aging of the tank internal surfaces using a program that requires an internal inspection of the tank when appropriate (e.g., the Closed
-Cycle Cooling Water Program requires a on e-time inspection of stagnant flow areas and internals of selected chemical mixing tanks). These programs include the Closed
-Cycle Cooling Water System, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components, Periodic Inspection, O ne-Time Inspection, and the Fire Water System programs. The staff finally notes that in appropriate cases, the LRA line items use a chemistry control program inclusive of the Water Chemistry, Fuel Oil Chemistry, Lubricating Oil Analysis, and Closed
-Cycle Cooling Water System programs. The staff finds these existing line items acceptable because (1) the chemistry control program will minimize contaminant concentrations and thus mitigate loss of material due to various corrosion mechanisms for tank internal surfaces at the fluid to air transition zone, and (2) the inspection
-related programs will provide reasonable assurance that an aging effect is not affecting the components intended function. The staff notes that in the case of some of the tanks included in LRA Tables 3.3.2-2, 3.3.2-21, and 3.3.2
-25, the LRA line items manage the aging of the tank internals using the Water Chemistry Program. The staff finds these existing line items acceptable because (1) the Water Chemistry Program will minimize contaminant concentrations and thus mitigate loss of material due to various corrosion mechanisms for tank internal surfaces at the fluid to air transition zone, (2) use of only the Water Chemistry Program is consistent with GALL Report items V.D1
-30, VII.E1
-17, and VII.A3
-8 and there are no other GALL Report line items in Sections V.D1, VII.E1, and VII.A3 related to tanks that require anything more than the Water Chemistry Program, and (3) the GALL Report recommends that there is no AERM or recommended AMP for stainless steel tanks exposed to uncontrolled indoor uncontrolled or condensation.
The staff concludes that 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).
LRA Tables 3.3.2-9 and 3.3.2
-14 were revised as a result of the July 8, 2010 response to RAI B.2.1.9-01.. The revision added AMR items in these tables to reference the applicant's Bolting Integrity Program to manage the aging for bolting AMR items. Existing bolting AMR items which reference other AMPs are used in conjunction with the added bolting AMR items to properly manage aging for bolting components. The staff's evaluation of the applicant's Bolting Integrity Program is documented in SER Section 3.0.3.2.2. The staff notes that the Bolting Integrity Program is supplemented by other AMPs including but not limited to the Structures Monitoring, Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems, External Surfaces Monitoring, and Buried Piping Inspection programs. These other AMPs supplement the Bolting Integrity Program by implementing the requirements of the Bolting Integrity Program for pressure
-retaining bolted joints, component support bolting, and structural bolting within the scope of license renewal. The applicant's action revised the LRA to add bolting component items in the tables mentioned above that are consistent with the GALL Report and have designated them as such with generic note B.
Aging Management Review Results 3-312 The staff did not repeat its review of the matters described in the GALL Report; however, it did verify that the material presented in the LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The staff's evaluation is discussed below.
The staff reviewed the LRA to confirm that the applicant:  (1) provided a brief description of the system, components, materials, and environments; (2) stated that the applicable aging effects were reviewed and evaluated in the GALL Report; and (3) identified those aging effects for the auxiliary systems components that are subject to an AMR.
On the basis of its audit and review, the staff determines that, for AMRs not requiring further evaluation, as identified in LRA Table 3.3.1, the applicant's references to the GALL Report are acceptable and no further staff review is required.
3.3.2.1.1  AMR Results Identified as Not Applicable LRA Table 3.3.1, line items 36
- 39, discuss the applicant's determination on GALL AMR line items that are applicable only to BWR
-designed reactors. In the applicant AMR discussions for line items 36
- 39, no additional information is provided. The staff confirmed that AMR line items 36 - 39, in Table 1 of the GALL Report, Volume 1 are only applicable to BWR designed reactors, and that Salem are PWRs. Based on this determination, the staff finds that AMR line items 36-39, in Table 1 of the GALL Report, Volume 1 are not applicable to Salem. LRA Table 3.3.1, item 3.3.1
-41 addresses high
-strength steel closure bolting exposed to air with steam or water leakage in the auxiliary systems. The GALL Report recommends use of GALL AMP XI.M18, "Bolting Integrity," to manage cracking due to cyclic loading or SCC for this component group. The applicant stated that this item is not applicable because there is no high-strength closure bolting in the auxiliary systems. The staff reviewed LRA Sections 2.3.3 and 3.3 and confirmed that the applicant's LRA does not have any AMR results for the auxiliary systems that include high
-strength steel closure bolting exposed to air with steam or water leakage. The staff reviewed the applicant's UFSAR and confirms that no, high
-strength steel closure bolting exposed to air with steam or water leakage within scope is present in the auxiliary systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.3.1, item 3.3.1
-42 addresses steel closure bolting exposed to air with steam or water leakage. The GALL Report recommends the use of GALL AMP XI.M18, "Bolting Integrity," to manage loss of material due to general corrosion for this component group. The applicant stated that this item is not applicable because the AMR methodology for steel closur e bolting exposed to air with steam or water leakage adds pitting and crevice corrosion to general corrosion and as a result, item 3.3.1
-43 is credited for this component instead. The staff evaluated the applicant's claim and found it acceptable because the applicant:  (1) identified the loss of material due to the general, pitting, and crevice corrosion aging effect, which is a more conservative approach than the loss of material due to the general corrosion aging effect for this component group and (2) has credited an alternate Table 1 line item (item 3.3.1-43) to manage this component group.
LRA Table 3.3.1, item 3.3.1
-44 addresses steel closure bolting exposed to air with steam or water leakage. The GALL Report recommends the use of GALL AMP XI.M18, "Bolting Integrity," to manage loss of material due to general corrosion for this component group. The applicant stated that this item is not applicable because there is no steel closure bolting exposed to air with steam or water leakage in the auxiliary systems. The staff reviewed LRA Sections 2.3.3 and 3.3 and confirmed that the applicant's LRA does not have any AMR results Aging Management Review Results 3-313 for the auxiliary systems that include steel closure bolting exposed to air with steam or water leakage. The staff reviewed the applicant's UFSAR and confirms that no steel closure bolting exposed to air with steam or water leakage within scope is present in the auxiliary systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.3.1, item 3.3.1-49 addresses loss of material due to microbiologically induced corrosion (MIC) for stainless steel and steel with stainless steel cladding heat exchanger components exposed to closed
-cycle cooling water. The applicant stated that this item is not applicable because this aging effect is not predicted for the corresponding components based on plant-specific operating experience. The staff reviewed the operating experience portion of LRA Section B.2.1.12 for the Closed
-Cycle Cooling Water System Program and noted that, although MIC had been identified in the diesel generator jacket water components exposed to closed-cycle cooling water, these components are titanium and thus are not susceptible to MIC. The staff finds the applicant's determination acceptable.
LRA Table 3.3.1, item 3.3.1
-53 addresses steel compressed air system piping, piping components, and piping elements exposed to condensation (internal). The GALL Report recommends use of GALL AMP XI.M24, "Compressed Air Monitoring," to manage loss of material due to general and pitting corrosion for this component group. The applicant stated that this item is not applicable because this component, material, and environment combination is addressed by item 3.3.1
-71 since item 3.3.1
-53 does not include crevice corrosion, which is predicted for Salem for this component, material, and environment combination. The staff evaluated the applicant's claim and found it acceptable because the applicant:  (1) identified the loss of material due to the general, pitting, and crevice corrosion aging effect, which is a more conservative approach than the loss of material due to general and pitting corrosion aging effect for this component group, and (2) has credited an alternate Table 1 line item (item 3.3.1
-71) to manage this component group. LRA Table 3.3.1, item 3.3.1
-62 addresses aluminum piping, piping components, and piping elements exposed to raw water. The GALL Report recommends the use of GALL AMP XI.M26, "Fire Protection," to manage loss of material due to pitting and crevice corrosion for this component group. The applicant stated that this line item is not applicable because the applicant does not have any aluminum piping, piping components, or piping elements exposed to raw water in the auxiliary systems. The staff reviewed LRA Sections 2.3.3 and 3.3 and noted that the applicant's LRA does have AMR results for aluminum piping, piping components, and piping elements exposed to raw water in the auxiliary systems, but that these components are evaluated using alternative line items because they are exposed to open
-cycle cooling water, and not fire water, so the Fire Protection Program would not be applicable. The staff also notes that item 3.3.1
-62 is only applicable for components in the fire protection system. The staff reviewed the applicant's UFSAR and confirms that no aluminum piping, piping components, and piping elements exposed to raw water within scope are present in the fire protection systems and, therefore, finds the applicant's determination acceptable.
LRA Tabl e 3.3.1, item 3.3.1
-64 addresses steel piping, piping components, and piping elements exposed to fuel oil. The GALL Report recommends the use of GALL AMPs XI.M30, "Fuel Oil Chemistry," and XI.M26, "Fire Protection," to manage loss of material due to general, pitting, and crevice corrosion for this component group. The applicant stated that this line item is not applicable because steel components exposed to fuel oil were aligned to item 3.3.1
-20, which includes loss of material due to MIC and fouling, which are applicable aging effects. The staff reviewed LRA Sections 2.3.3 and 3.3 and confirms that the applicant's LRA does have AMR results for steel piping, piping components, and piping elements exposed to fuel oil in the Aging Management Review Results 3-314 auxiliary systems and that these items are being managed using item 3.3.1
-20. The staff finds the applicant's determination acceptable because the components are being managed for aging in accordance with an appropriate alternative line item.
LRA Table 3.3.1, item 3.3.1
-65 addresses reinforced structural fire barriers (i.e., walls, ceiling, and floors) exposed to uncontrolled indoor air. The GALL Report recommends the use of GALL AMPs XI.M26, "Fire Protection," and XI.S6, "Structures Monitoring Program," to manage concrete cracking and spalling due to aggressive chemical attack and reaction with aggregates for this component group. The applicant stated that this line item is not applicable because the applicant addressed these aging effects and environments in LRA Section 3.5 for the appropriate buildings. The staff reviewed LRA Sections 3.3 and 3.5 and confirms that structural fire barrier walls, ceilings, and floors exposed to indoor air are being managed for cracking and spalling by alternative line items from LRA Section 3.5. The staff finds the applicant's determination acceptable because the components are being managed for aging in accordance with an appropriate alternative line item.
LRA Table 3.3.1, item 3.3.1
-69 addresses stainless steel piping, piping components, and piping elements exposed to raw water. The GALL Report recommends the use of GALL AMP XI.M27 "Fire Water System," to manage loss of material due to pitting and crevice corrosion and fouling for this component group. The applicant stated that this line item is not applicable because stainless steel components exposed to raw water were aligned to item 3.4.1
-33, which includes loss of material due to MIC, which is an applicable aging effect. The staff reviewed LRA Sections 2.3.3 and 3.3 and confirms that the applicant's LRA does have AMR results for stainless steel piping, piping components, and piping elements exposed to raw water in the auxiliary systems and that these items are being managed using item 3.4.1
-33. The staff finds the applicant's determination acceptable because the components are being managed for aging in accordance with an appropriate alternative line item.
LRA Table 3.3.1, item 3.3.1-78 addresses loss of material due to pitting and crevice corrosion for stainless steel, nickel
-alloy, and copper alloy piping, piping components, and piping elements exposed to raw water. The applicant stated that this item is not applicable because the corresponding components exposed to raw water require consideration of MIC, which are evaluated in item 3.3.1-80. The staff notes that item 3.3.1-80 included all the aging mechanisms in item 3.3.1-78 plus MIC. The staff reviewed LRA Sections 2.3.3 and 3.3 and noted that the corresponding components had been evaluated using item 3.3.1-80, and therefore, finds the applicant's determination acceptable.
LRA Table 3.3.1, item 3.3.1-79 addresses loss of material due to pitting and crevice corrosion and fouling for stainless steel piping, piping components, and piping elements exposed to raw water. The applicant stated that this item is not applicable because the component, material, environment, and aging effect combination do not apply to stainless steel materials in the auxiliary systems. The staff reviewed LRA Sections 2.3.3 and 3.3 and confirms that the applicant's LRA does not have any AMR results for this material environment and aging effect combination and, therefore, finds the applicant's determination acceptable.
LRA Table 3.3.1, item 3.3.1
-87 addresses reduction of neutron
-absorbing capacity due to Boraflex degradation in Boraflex spent fuel storage rack neutron
-absorbing sheets exposed to treated water. The applicant stated that this line item is not applicable because there are no Boraflex spent fuel storage rack neutron
-absorbing sheets exposed to treated water for the auxiliary systems. The staff reviewed LRA Sections 2.3.3 and 3.3 and confirms that the applicant's LRA does not have any AMR results that include Boraflex spent fuel storage rack Aging Management Review Results 3-315 neutron-absorbing sheets exposed to treated water. The staff also reviewed the applicant's UFSAR and confirms that no Boraflex spent fuel storage rack neutron
-absorbing sheets exposed to treated water within scope are present in the spent fuel storage system and, therefore, finds the applicant's determination acceptable. LRA Table 3.3.1, item 3.3.1
-95 addresses steel and aluminum piping, piping components, and piping elements externally exposed to indoor controlled air. The applicant stated that this line item is not applicable because all indoor air was assumed to be uncontrolled for the purposes of license renewal. The staff reviewed LRA Sections 2.3.3 and 3.3 and confirmed that the applicant's LRA does have AMR results for steel and aluminum piping, piping components, and piping elements externally exposed to indoor uncontrolled air and that those items are being managed by alternative line items applicable to indoor uncontrolled air. The staff finds the applicant's determination acceptable because uncontrolled air is a more aggressive environment than controlled air and the items are being managed by appropriate alternative line items. 3.3.2.1.2  Loss of Material Due to Pitting and Crevice Corrosion LRA Table 3.3.1, item 3.3.1-27 addresses stainless steel HVAC ducting and aluminum HVAC piping, piping components, and piping elements exposed to condensation for loss of material due to pitting and crevice corrosion. The LRA credits the Periodic Inspection Program to manage the aging effect for stainless steel piping and fittings and valve bodies in Table 3.3.2-7. The GALL Report recommends GALL AMP XI.M24, "Compressed Air Monitoring," to ensure that these aging effects are adequately managed. The associated AMR line item cites generic note E. For those line items associated with generic note E, GALL AMP XI.M24 recommends visua l inspections, monitoring the level of contaminants, and leak rate testing of the entire system, especially of components made of carbon and stainless steels, for loss of material in the compressed air system. The AMP discusses preventive maintenance only in the context of the inoperability of air
-operated components impacted by corrosion and other contaminants. In its review of the LRA of components associated with item 3.3.1-27 for which the applicant cited generic note E, the staff notes that the Periodic Inspection Program proposes to manage the aging effects in stainless steel and aluminum piping and its components and elements with visual and volumetric inspections for loss of material.
The staff's evaluation of the applicant's Periodic Inspection Program is documented in SER Section 3.0.3.3.2. In addition to that review, the staff also reviewed NUREG
-1833, "Technical Bases for Revision to the License Renewal Guidance Documents," and notes that although GALL AMP XI.M24 is recommended for this function, a plant
-specific program based on the same inspection techniques could also be credited providing the assurance that the components' intended functions will be maintained within the CLB for the period of extended operation. In its review of components associated with item 3.3.1-27, the staff finds the applicant's proposal to manage aging effects using the Periodic Inspection Program acceptable because it includes:  (1) periodic visual inspections of piping and fittings and valve bodies and (2) ultrasonic wall thickness measurements of piping systems, which are adequate to detect loss of material, thinning, and fouling.
The staff concludes that 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 Aging Management Review Results 3-316 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, Pitting, and Crevice Corrosion LRA Table 3.3.1, item 3.3.1
-43 addresses steel bolting and closure bolting exposed externally to indoor air or outdoor air, which is being managed for loss of material due to general, pitting, and crevice corrosion. The LRA credits the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program to manage the aging effect. The GALL Report recommends GALL AMP XI.M18, "Bolting Integrity," to ensure that these aging effects are adequately managed. The associated AMR line item cites generic note E. For those line items associated with generic note E, GALL AMP XI.M18 recommends using visual inspections to manage the aging of these line items. In its review of components associated with item 3.3.1
-43 for which the applicant cited generic note E, the staff notes that the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program proposes to manage the aging of carbon and low
-alloy steel bolting through the use of visual inspections.
The staff's evaluation of the applicant's Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program is documented in SER Section 3.0.3.2.4. In its review of components associated with item 3.3.1
-43, the staff finds the applicant's proposal to manage aging using the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program acceptable because (1) its visual inspections are effective methods for detecting the applicable aging effects, (2) the frequency of monitoring is adequate to prevent significant degradation, and (3) the methods are consistent with the GALL Report recommended AMP.
The staff concludes that 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).
3.3.2.1.4  Loss of Preload Due to Self
-Loosening LRA Table 3.3.1, item 3.3.1
-45 addresses steel closure bolting exposed externally to indoor air, which is being managed for loss of preload due to self
-loosening. The LRA credits the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program to manage the aging effect. The GALL Report recommends GALL AMP XI.M18, "Bolting Integrity," to ensure that these aging effects are adequately managed. The associated AMR line item cites generic note E. For those line items associated with generic note E, GALL AMP XI.M18 recommends using visual inspections and industry guidance on proper selection of bolting materials, lubricants, and torque to manage the aging of these line items. In its review of components associated with item 3.3.1
-45 for which the applicant cited generic note E, the staff noted that the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program proposes to manage the aging of carbon and low
-alloy steel bolting through the use of visual inspections and industry guidance on bolting materials, lubricants, and torque.
 
Aging Management Review Results 3-317 The staff's evaluation of the applicant's Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program is documented in SER Section 3.0.3.2.4. In its review of components associated with item 3.3.1
-45, the staff finds the applicant's proposal to manage aging using the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program acceptable because (1) its visual inspections are effective methods for detecting the applicable aging effects; (2) incorporation of industry guidance on proper selection of bolting materials, lubricants, and torque are effective methods for preventing loss of preload; (3) the frequency of monitoring is adequate to prevent significant degradation; and (4) the inspection methods are consistent with the GALL Report recommended AMP.
The staff concludes that 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).
3.3.2.1.5  Loss of Material Due to Pitting and Crevice Corrosion LRA Table 3.5.1, item 3.5.1-50 addresses galvanized steel, aluminum, stainless steel support members, welds, bolted connections, support anchorage to building structures exposed to outdoor air which are being managed for loss of material due to pitting and crevice corrosion. The LRA credits the Periodic Inspection Program to manage the aging effect for aluminum louvers, flame arrestor, bird screen, and insulation jacketing (wire mesh, straps, and clips) and stainless steel piping and fittings, restricting orifices, valve bodies, bird screens, thermowells, insulation jacketing (wire mesh, straps, and clips), and bolting in Tables 3.2.2-3, 3.3.2-1, 3.3.2-2, 3.3.2-8, 3.3.2-16, 3.3.2-19, 3.3.2-23, 3.3.2-24, 3.4.2-4, and 3.5.2
-9. The GALL Report recommends GALL AMP XI.S6, "Structures Monitoring Program," to ensure that these aging effects are adequately managed. The associated AMR line item cites generic note E. For those line items associated with generic note E, GALL AMP XI.S6 is a plant
-specific program that follows 10 CFR 50.65, "The Maintenance Rule"; RG 1.160, Revision 2, "Monitoring the Effectiveness of Maintenance at Nuclear Power Plants"; and references ANSI/American Society of Civil Engineers (ASCE) 11-90, "Guideline for Structural Condition Assessment of Existing Buildings."  These codes, industry standards, and guidelines recommend periodic visual inspections, NDE tests, and destructive tests (field and laboratory) supplemented by additional testing or analysis as required for proper evaluation of aging effects. In its review of the LRA of components associated with item 3.5.1
-50 for which the applicant cited generic note E, the staff notes that the Periodic Inspection Program proposes to manage the aging effects of aluminum and stainless steel piping and fittings, insulation, and other related components as listed above exposed to outdoor air, through periodic visual and volumetric inspection methods for loss of material due to pitting and crevice corrosion.
The staff's evaluation of the applicant's Periodic Inspection Program is documented in SER Section 3.0.3.3.2. In addition, the staff reviewed NUREG
-1833, "Technical Bases for Revision to the License Renewal Guidance Documents," and notes that stainless steel and aluminum in an outdoor air environment could result in loss of material. This review also notes that although the Structures Monitoring Program manages this aging effect by performing routine visual inspections of the structural materials' surfaces, a similar program based on the same inspection techniques could also be credited, providing a reasonable assurance that the components' intended functions will be maintained within the CLB for the period of extended operation. In its review of components associated with item 3.3.1-50, the staff finds the Aging Management Review Results 3-318 applicant's proposal to manage aging effects using the Periodic Inspection Program acceptable because it includes periodic visual inspections of components and ultrasonic wall thickness measurements of piping and its components that are appropriate to detect loss of material.
The staff concludes that 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).
3.3.2.1.6  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. The LRA credits the Fire Protection Program to manage loss of material for stainless steel spray nozzles, piping and fittings, and valve bodies exposed to wetted air or gas in the fire protection system. The GALL Report recommends GALL AMP XI.M24, "Compressed Air Monitoring," to ensure that these aging effects are adequately managed. The AMR line items cite generic note E. The LRA also cites plant-specific Note 2, indicating that the Fire Protection Program is substituted to manage the aging effects applicable to this component type, material, and environment combination.
GALL AMP XI.M24 recommends control of contaminants in order to limit loss of material due to corrosion and leakage testing to detect loss of material. In its review of components associated with item 3.3.1
-54 for which the applicant cited generic note E, the staff notes that the applicant credited the Fire Protection Program to manage loss of material for stainless steel spray nozzles, piping and fittings, and valve bodies exposed internally to wetted air or gas in LRA Table 3.3.2-12. The staff reviewed the applicant's Fire Protection Program and its evaluation is documented in SER Section 3.0.3.2.5. The staff notes that the Fire Protection Program manages aging for:  (1) fire barriers by performing visual inspections, (2) the diesel driven fire pump fuel supply lines through performance testing, and (3) the external surfaces of the halon and CO 2 systems through visual inspection. However, the description of the Fire Protection Program does not include criteria for inspections of the internal surfaces of components or leakage testing which could detect loss of material. It is not clear to the staff how the Fire Protection Program is adequate to manage loss of material for these stainless steel components exposed internally to wetted air or gas.
By a June 25, 2010 letter, the staff issued RAI 3.3.2.12-02 requesting that the applicant justify how the Fire Protection Program will adequately manage loss of material due to pitting and crevice corrosion for the stainless steel components exposed to an internal environment of wetted air or gas.
In its July 21, 2010 response, the applicant stated that the Fire Protection Program does not inspect the internal surfaces of components and was not the appropriate program to manage loss of material for components exposed to internal condensation, which are part of the fire water suppression systems. As a result, the applicant revised the AMR line items in LRA Table 3.3.2-12 for the stainless steel iodine removal filter spray nozzles, piping and fittings, and valve bodies that reference item 3.3.1
-54 to credit the Fire Water System Program to manage loss of material. The staff finds the applicant's response to RAI 3.3.2.12-02 and its use of the Aging Management Review Results 3-319 Fire Water System Program to manage loss of material for these components exposed to internal condensation acceptable because (1) the components are not part of the compressed air system so the preventive measures in the GALL Report recommended AMP would not be appropriate; and (2) the Fire Water System Program includes volumetric inspections, system performance testing, and flow tests which are capable of detecting loss of material in components exposed to internal condensation.
In addition, the applicant stated in its response to RAI 3.3.2.12-02 that the stainless steel spray nozzles in the halon and CO 2 systems are open such that the internal surfaces are exposed to the same environment as the external surfaces, which is indoor air. As a result, the applicant revised the AMR result lines in LRA Table 3.3.2-12 for the halon and CO 2 stainless steel spray nozzles to change the environment to indoor air and change the Table 1 item reference to item 3.3.1-94 with no AERMs or AMP, citing generic note A. The applicant also stated that additional AMR results were required in order to distinguish between those portions of the fire protection system which are subject to internal condensation (i.e., components in the fire water suppression systems) and those which are not (i.e., components in the halon and CO 2 suppression systems that are downstream of the isolation valves). As a result, the applicant also revised LRA Table 3.3.2-12 to add two new AMR result lines for stainless steel piping and fittings and valve bodies exposed internally to indoor air which reference item 3.3.1
-94, have no AERMs and no AMP, and cite generic note A. The staff finds the applicant's response acceptable because (1) the internal environment for components downstream from the isolatio n valves in the halon and CO 2 fire suppression systems should be the same as the external environment; (2) the external environment for the halon and CO 2 fire suppression systems is indoor air, which is not expected to contribute to corrosion of these components; (3) the applicant has chosen appropriate alternate line items that recommend no aging effects for these components when exposed to an indoor air environment; and (4) the applicant has made the corresponding revisions to the LRA. The staff's concern described in RAI 3.3.2.12-02 is resolved. 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 for loss of material due to pitting and crevice corrosion. The LRA credits the Periodic Inspection Program to manage the aging effect for stainless steel strainers, piping and fittings, valve bodies, pump casings, filter housing, flow element, thermowell, and heat exchanger components in Tables 3.3.2-6, 3.3.2-11, 3.3.2-14, 3.3.2-19, and 3.3.2
-21. The GALL Report recommends GALL AMP XI.M24, "Compressed Air Monitoring," to ensure that these aging effects are adequately managed. The associated AMR line items cite generic note E. For those line items associated with generic note E, GALL AMP XI.M24 recommends visual inspections, monitoring the level of contaminants, and leak rate testing of the entire system, especially of components made of carbon and stainless steels, for loss of material in the compressed air system. The AMP discusses preventive maintenance only in the context of the inoperability of air
-operated components impacted by corrosion and other contaminants. In its review of the LRA of components associated with item 3.3.1-54 for which the applicant cited generic note E, the staff notes that the Periodic Inspection Program proposes to manage the aging effects of passive stainless steel piping system components and other elements as described above (e.g., strainers, pump casings, filter housing, flow element, thermowell, etc.) and heat exchanger components with visual and volumetric inspections for loss of material, thinning, and fouling that could result in reduction of heat transfer.
 
Aging Management Review Results 3-320 The staff's evaluation of the applicant's Periodic Inspection Program is documented in SER Section 3.0.3.3.2. In addition to that review, the staff also reviewed NUREG
-1833, "Technical Bases for Revision to the License Renewal Guidance Documents," and notes that although GALL AMP XI.M24 is recommended for this function, a similar program based on the same inspection techniques could also be credited providing the assurance that the components' intended functions will be maintained within the CLB for the period of extended operation. In its review of components associated with item 3.3.1-54, the staff finds the applicant's proposal to manage aging effects using the Periodic Inspection Program acceptable because it includes periodic visual inspections of components and ultrasonic wall thickness measurements of piping systems and heat exchanger components which are adequate to detect loss of material, thinning, and fouling.
The staff concludes that 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).
3.3.2.1.7  Loss of Material Due to General Corrosion LRA Table 3.3.1, item 3.3.1
-57 addresses steel piping and components external surfaces exposed to indoor uncontrolled air, which are being managed for loss of material due to general corrosion. LRA Table 3.3.1, item 3.3.1
-58 addresses steel piping and components external surfaces exposed to indoor uncontrolled air, outdoor air, and condensation, which are being managed for loss of material due to general corrosion. The LRA credits the Fire Protection Program in addition to the External Surfaces Monitoring Program to manage aging for steel gas bottles, CO 2 tanks, piping and fittings, and steel and galvanized steel fire barrier doors in the fire protection system. The GALL Report recommends GALL AMP XI.M36, "External Surfaces Monitoring," to ensure that these aging effects are adequately managed. The AMR line items that credit the Fire Protection Program cite generic note E. The LRA also cites plant
-specific Note 10, which indicates that the Fire Protection Program will be used in addition to the External Surfaces Monitoring Program.
The staff reviewed the applicant's Fire Protection Program and its evaluation is documented in SER Section 3.0.3.2.5. In its review of components associated with items 3.3.1
-57 and 3.3.1-58, the staff notes that the Fire Protection Program proposes to manage loss of material for the external surfaces of these steel components through the use of periodic visual inspections. GALL AMP XI.M36 also recommends using periodic visual inspections of the external surfaces of steel components to manage these aging effects. The staff finds the LRA proposed AMP acceptable because (1) the proposed inspection methods are the same as the inspection methods in the GALL Report recommended AMP and (2) the applicant is using the Fire Protection Program in addition to the External Surfaces Monitoring Program, which provides a more comprehensive approach to managing this aging effect.
LRA Table 3.3.1, items 3.3.1
-57 and 3.3.1
-58 address steel piping and components external surfaces exposed to indoor uncontrolled air, outdoor air, and condensation, which are being managed for loss of material due to general corrosion. The LRA credits the Fire Water System Program in addition to the External Surfaces Monitoring Program for cast iron flow alarm switches, diesel driven fire pump casing, strainer bodies, and valve bodies and carbon steel piping and fittings, jockey fire pump casing, and retarding chamber tanks exposed to indoor air in the fire protection system. The GALL Report recommends GALL AMP XI.M36, "External Surfaces Monitoring," to ensure that these aging effects are adequately managed. The AMR Aging Management Review Results 3-321 line items that credit the Fire Water System Program cite generic Note E. The AMR line items also cite plant
-specific Note 8, which indicates that the Fire Water System Program will be used in addition to the External Surfaces Monitoring Program.
The staff reviewed the applicant's Fire Water System Program and its evaluation is documented in SER Section 3.0.3.2.6. In its review of components associated with Table 3.3-1, items 3.3.1-57 and 3.3.1
-58, the staff notes that the Fire Water System Program proposes to manage the aging effects of these items through the use of periodic visual inspections. GALL AMP XI.M36 also recommends using periodic visual inspections of the external surfaces of steel components to manage these aging effects. The staff finds the LRA proposed AMP acceptable to manage aging for these components because (1) the proposed inspection methods are the same as the methods in the GALL Report recommended AMP and (2) the applicant is using the Fire Water System Program in addition to the External Surfaces Monitoring Program, which provides a more comprehensive approach to managing this aging effect.
LRA Table 3.3.1, item 3.3.1
-58 addresses steel external surfaces that are being managed for loss of material due to general corrosion. The LRA credits the Structures Monitoring Program to manage the aging effect. The GALL Report recommends GALL AMP XI.M36, "External Surfaces Monitoring," to ensure that these aging effects are adequately managed. The associated AMR line item in LRA Table 3.3.2-14 cites generic note E. For those line items associated with generic note E, GALL AMP XI.M36 recommends using general visual inspections of external surfaces to manage the aging of these line items. In its review of components associated with item 3.3.1
-58 for which the applicant cited generic note E and the Structures Monitoring Program, the staff noted that the Structures Monitoring Program proposes to manage the aging of steel surfaces of new fuel storage racks through the use of visual inspections.
The staff's evaluation of the applicant's Structures Monitoring Program is documented in SER Section 3.0.3.2.15. In its review of components associated with item 3.3.1
-58, the staff finds the applicant's proposal to manage aging using the Structures Monitoring Program acceptable because the applicant's program uses visual inspections which are equivalent to the inspections recommended by GALL AMP XI.M36.
The staff concludes that 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).
3.3.2.1.8  Loss of Material Due to General, Pitting, and Crevice Corrosion LRA Table 3.3.1, items 3.3.1
-59 and 3.3.1
-60 address steel heat exchanger components, piping, piping components, and piping elements exposed to indoor uncontrolled air or outdoor air which are being managed for loss of material due to general, pitting, and crevice corrosion. The LRA credits the Fire Water System Program in addition to the External Surfaces Monitoring Program to manage aging for steel piping and fittings, gray cast iron fire hydrants and hose manifolds, and ductile cast iron piping and fittings exposed to outdoor air or air with steam or water leakage in the fire protection system. The GALL Report recommends GALL AMP XI.M36, "External Surfaces Monitoring," to ensure that these aging effects are adequately managed. The AMR line items that credit the Fire Water System Program cite generic note E. The AMR Aging Management Review Results 3-322 line items also cite plant
-specific Note 8, indicating that the Fire Water System Program will be used in addition to the External Surfaces Monitoring Program.
The staff reviewed the applicant's Fire Water System Program and its evaluation is documented in SER Section 3.0.3.2.6. In its review of components associated with Table 3.3-1, items 3.3.1-59 and 3.3.1
-60, the staff notes that the Fire Water System Program proposes to manage the aging effects of these components through the use of periodic visual inspections. GALL AMP XI.M36 also recommends using periodic visual inspections of the external surfaces of steel components to manage these aging effects. The staff finds the LRA proposed AMP acceptable to manage aging for these components because (1) the proposed inspection methods are the same as the methods in the GALL Report recommended AMP and (2) the applicant is using the Fire Water System Program in addition to the External Surfaces Monitoring Program, which provides a more comprehensive approach to managing this aging effect. LRA Table 3.3.1, item 3.3.1
-59 addresses steel heat exchanger components exposed to indoor uncontrolled air or outdoor air, which are being managed for loss of material due to general, pitting, and crevice corrosion. The LRA credits the Fire Protection Program to manage aging for steel and galvanized steel fire barrier doors exposed to outdoor air in the fire protection system. The GALL Report recommends GALL AMP XI.M36, "External Surfaces Monitoring," to ensure that these aging effects are adequately managed. The AMR line items cite generic note E. The LRA also cites plant
-specific Note 2, indicating that the Fire Protection Program will be substituted for the External Surfaces Monitoring Program.
The staff reviewed the applicant's Fire Protection Program and its evaluation is documented in SER Section 3.0.3.2.5. In its review of components associated with item 3.3.1
-59, the staff notes that the Fire Protection Program proposes to manage loss of material for the steel and galvanized steel fire barrier doors through the use of periodic visual inspections. GALL AMP XI.M36 also recommends using periodic visual inspections of the external surfaces of steel components to manage these aging effects. The staff finds the LRA proposed AMP acceptable because the proposed inspection methods are the same as the methods in the GALL Report recommended AMP.
LRA Table 3.3.1, item 3.3.1
-60 addresses steel piping, piping components, and piping elements exposed externally to outdoor air, which are being managed for loss of material due to general, pitting, and crevice corrosion. The LRA credits the Fire Protection Program in addition to the External Surfaces Monitoring Program to manage aging for steel and galvanized steel piping and fittings exposed to outdoor air in the fire protection system. The GALL Report recommends GALL AMP XI.M36, "External Surfaces Monitoring," to ensure that these aging effects are adequately managed. The AMR line items that credit the Fire Protection Program cite generic note E. The LRA also cites plant
-specific Note 10, which indicaties that the Fire Protection Program will be used in addition to the External Surfaces Monitoring Program.
The staff reviewed the applicant's Fire Protection Program and its evaluation is documented in SER Section 3.0.3.2.5. In its review of components associated with item 3.3.1
-60, the staff notes that the Fire Protection Program proposes to manage loss of material for the steel and galvanized steel piping and fittings external surfaces through the use of periodic visual inspections. GALL AMP XI.M36 also recommends using periodic visual inspections of the external surfaces of steel components to manage these aging effects. The staff finds the LRA proposed AMP acceptable because (1) the proposed inspection methods are the same as those in the GALL Report recommended AMP, and (2) the applicant is using the Fire Protection Aging Management Review Results 3-323 Program in addition to the External Surfaces Monitoring Program, which provides a more comprehensive approach to managing this aging effect.
LRA Table 3.3.1, item 3.3.1
-60 addresses steel piping, piping components, and piping elements exposed externally to outdoor air, which are being managed for loss of material due to general, pitting, and crevice corrosion. The LRA credits the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program to manage the aging effect. The GALL Report recommends GALL AMP XI.M36, "External Surfaces Monitoring," to ensure that these aging effects are adequately managed. The associated AMR line item cites generic note E. For those line items associated with generic note E, GALL AMP XI.M36 recommends using visual inspections to manage the aging of these line items. In its review of components associated with item 3.3.1
-60 for which the applicant cited generic note E, the staff notes that the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program proposes to manage the aging of carbon steel cranes and hoists through the use of visual inspections.
The staff's evaluation of the applicant's Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program is documented in SER Section 3.0.3.2.4. In its review of components associated with item 3.3.1
-60, the staff finds the applicant's proposal to manage aging using the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program acceptable because (1) its visual inspections are effective methods for detecting the applicable aging effects, (2) the frequency of monitoring is adequate to prevent significant degradation, and (3) the proposed inspection method is consistent with the method in the GALL Report recommended AMP.
The staff concludes that 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).
3.3.2.1.9  Loss of Material Due to General, Pitting, Crevice, Galvanic, and Microbiologically
-Influenced Corrosion and Fouling LRA Table 3.3.1, item 3.3.1
-68 addresses steel piping, piping components, and elements exposed to raw water, which are being managed for loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion and fouling. The LRA credits the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage the aging effect for carbon steel piping, fittings, and valve bodies and gray cast iron pump casings, tanks (HHB condensate receiver and level pot), and drain traps in Tables 3.3.2-5, 3.3.2-17, 3.3.2-18, and 3.3.2
-21. The GALL Report recommends GALL AMP XI.M27, "Fire Water System," to ensure that these aging effects are adequately managed. The associated AMR line items cite generic note E. For those line items associated with generic note E, GALL AMP XI.M27 recommends routine (or during corrective maintenance) visual inspections of piping internals as an alternate method to identify loss of material and wall thinning, verify the existence of unobstructed internal flow, and ensure their fitness against catastrophic failure. In its review of components associated with item 3.3.1
-68, for which the applicant cited generic note E, the staff notes that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program proposes to Aging Management Review Results 3-324 manage loss of material through visual inspections during surveillances, maintenance activities, and outages. The applicant stated that when the inspections yield evidence of loss of material or fouling that could potentially impair these components' intended functions, it evaluates the components' degraded condition and, if warranted, implements its corrective action program.
The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.1.15. The staff notes that the performance of periodic visual inspections, further evaluation of potentially impaired components, and application of the corrective action program for degraded components provide similar detection and prevention methods as those recommended in the GALL AMP XI.M27. In its review of components associated with 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 because the visual inspection techniques used in the two programs to detect loss of material have no substantive differences.
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 microbiologically
-influenced corrosion and fouling. The LRA credits the Fire Water System Program to manage loss of material for gray cast iron retarding chamber tanks exposed to raw water in Table 3.3.2-12. The AMR line items cite generic Note C. The staff's evaluation of the applicant's Fire Water System Program is documented in SER Section 3.0.3.2.6. The staff notes that the Fire Water System Program includes wall thickness evaluations of fire protection piping using non
-intrusive techniques (e.g., volumetric testing) to identify loss of material due to corrosion. It is not clear from a review of the applicant's Fire Water System Program whether volumetric inspections to detect loss of material due to corrosion will be performed on the internal surfaces (specifically the bottom) of the retarding chamber tanks. By a June 17, 2010 letter, the staff issued RAI 3.3.2.12-01 which requested that the applicant clarify if these tanks are included in the sample of fire protection system components that will be volumetrically inspected for wall thickness to detect loss of material prior to loss of intended function.
In its July 15, 2010 response, the applicant stated that it does not use retarding chamber tanks in the portion of the fire protection system that is within the scope of license renewal, but instead uses time delays. The applicant also stated that retarding chamber tanks are only used in the portions of the system that are not within the scope of license renewal and were inadvertently included in LRA Table 3.3.2-12. The applicant revised LRA Table 3.3.2-12 to delete the AMR results related to the retarding chamber tanks. The staff finds the applicant's response to RAI 3.3.2.12-01 acceptable because the retarding chamber tanks are not within the scope of license renewal and, therefore, do not require aging management.
LRA Table 3.3.1, item 3.3.1-70 addresses copper alloy piping, piping components, and piping elements exposed to raw water for loss of material due to pitting, crevice, and microbiologically
-influenced corrosion and fouling. The LRA credits the Periodic Inspection Program to manage the aging effect for copper
-Zinc alloyed valve bodies internally exposed to raw water in Table 3.3.2-18. The GALL Report recommends GALL AMP XI.M27, "Fire Water System," to ensure that these aging effects are adequately managed. The associated AMR line item cites generic note E. For those line items associated with generic note E, GALL AMP XI.M27 recommends routine (or during corrective maintenance) visual inspections of piping internals as an alternate method to Aging Management Review Results 3-325 identify loss of material and wall thinning, verify the existence of unobstructed internal flow, and ensure their fitness against catastrophic failure. In its review of components associated with item 3.3.1-70, for which the applicant cited generic note E, the staff noted that the Periodic Inspection Program proposes to manage piping system loss of material through visual inspections, followed up with volumetric inspections at locations most susceptible to aging effects during maintenance activities based on industry and plant
-specific operating experience. The applicant stated that when the inspections yield evidence of loss of material or fouling that could potentially impair these components' intended function, it evaluates the components' degraded condition and, if warranted, implements its corrective action program.
The staff's evaluation of the applicant's Periodic Inspection Program is documented in SER Section 3.0.3.3.2. The staff notes that the Periodic Inspection Program includes periodic visual inspections of components and ultrasonic wall thickness measurements of piping and its components to detect loss of material and fouling. The staff also notes that the components included in item 3.3.1-70 are made of copper with less than 15 percent Zinc and, therefore, are resistant to SCC, selective leaching, and pitting and crevice corrosion. The staff further notes that although NUREG
-1833, "Technical Bases for Revision to the License Renewal Guidance Documents," recommends GALL AMP XI.M27 for this function, it also discusses that each time such systems are opened, the introduced oxygen could result in possible loss of material in components. In lieu of intrusive inspections, the staff recommends volumetric testing of the system, when possible. The applicant's Periodic Inspection Program provides for both visual and volumetric inspections of the piping system for the detection of loss of material and fouling, thus providing a reasonable assurance that the components' intended functions will be maintained within the CLB for the period of extended operation. In its review of components associated with item 3.3.1-70, the staff finds the applicant's proposal to manage aging using the Periodic Inspection Program acceptable because it includes periodic visual and volumetric inspections of the piping system and its components to detect loss of material, thinning, and fouling. The staff concludes that 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).
3.3.2.1.10 Loss of Material due to General, Pitting and Crevice Corrosion LRA Table 3.3.1, item 3.3.1
-71 addresses steel piping, piping components, and piping elements exposed internally to moist air or condensation which are being managed for loss of material due to general, pitting, and crevice corrosion. The LRA credits the Fire Protection and Fire Water System Programs to manage these aging effects for steel piping and fittings in the fire protection system. The GALL Report recommends GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program" to ensure that these aging effects are adequately managed. The AMR line items cite generic note E. The AMR line item that credits the Fire Protection Program also cites plant
-specific Note 2, which indicates that the Fire Protection program is substituted to manage the aging effect(s) applicable to this component type, material, and environment combination. The AMR line item that credits the Fire Water System Program also cites plant
-specific Note 9, which indicates that the Fire Water System Program is substituted to manage the aging effect(s) applicable to this component type, material, and environment combination.
 
Aging Management Review Results 3-326 GALL AMP XI.M38 recommends inspections of the internal surfaces of piping and components to detect loss of material. In its review of components associated with Table 3.3-1, item 3.3.1-71 for which the applicant cited generic Note E, the staff noted that the applicant credited the Fire Protection Program to manage loss of material for steel piping and fitting exposed internally to wetted air or gas in LRA Table 3.3.2-12. The staff reviewed the applicant's Fire Protection and Fire Water System Programs and its evaluations are documented in SER Sections 3.0.3.2.5 and 3.0.3.2.6, respectively. The staff notes that the Fire Protection Program manages the aging effects for (1) fire barriers by performing visual inspections, (2) the diesel driven fire pumps fuel supply lines through performance testing, and (3) the external surfaces of halon and CO2 systems through visual inspection. However, the staff also notes that the description of the Fire Protection Program does not include criteria for inspections of the internal surfaces of components or leakage testing which could detect loss of material, which is included in the GALL Report recommended AMP. It is not clear to the staff how the Fire Protection Program is adequate to manage loss of material for these components exposed internally to wetted air or gas. By a June 25, 2010 letter, the staff issued RAI 3.3.2.12-02, requesting that the applicant justify how the Fire Protection Program will adequately manage loss of material due to pitting and crevice corrosion for the components exposed to an internal environment of wetted air or gas; and clarify if both the Fire Protection Program and Fire Water System Programs will be used to manage loss of material for these components.
In its July 21, 2010 response, the applicant stated that the carbon dioxide dispersion system contains carbon steel piping and fittings between the isolation valves and open spray nozzles that are exposed to the same environment as the external surfaces. The applicant also stated that the environment was conservatively listed as wetted air or gas, but that these components are not subject to internal condensation. As a result, the applicant revised the AMR line item that credited the Fire Protection Program to change the environment to indoor air, and change the credited program to the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, citing generic note A, which indicates that the line item is being managed consistent with the GALL Report recommendations. The staff finds the applicant's response to RAI 3.3.2.12-02 and its use of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Programs acceptable to manage aging for these components exposed to indoor air because it includes visual inspections of the internal surfaces of components which are capable of detecting loss of material and is consistent with the GALL Report recommendations for managing aging for these components. The staff also finds the applicant's use of the Fire Water System Program acceptable to manage the components exposed to internal condensation because it includes volumetric inspections, system performance testing, and flow tests which are capable of detecting loss of material in components exposed to internal condensation. The staff concludes that 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).
3.3.2.1.11 Loss of Material Due to General, Pitting, Crevice, and (For Drip Pans and Drain Lines) Microbiologically
-Influenced Corrosion LRA Table 3.3.1, item 3.3.1
-72 addresses steel HVAC ducting and components internal surfaces exposed to internal condensation, which are being managed for loss of material due to Aging Management Review Results 3-327 general, pitting, crevice, and (for drip pans and drain lines) microbiologically
-influenced corrosion. The LRA credits the Fire Protection Program for galvanized steel damper housings in the fire protection system. The GALL Report recommends GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program," to ensure that these aging effects are adequately managed. The AMR line item cites generic note E. The LRA also cites plant
-specific Note 2, indicating that the Fire Protection Program is substituted to manage the aging effects applicable to this component type, material, and environment combination.
GALL AMP XI.M38 recommends inspections of the internal surfaces of piping and components to detect loss of material. In its review of components associated with Table 3.3-1, item 3.3.1-72 for which the applicant cited generic Note E, the staff noted that the applicant credited the Fire Protection Program to manage loss of material for galvanized steel damper housings exposed internally to wetted air or gas.
The staff reviewed the applicant's Fire Protection Program and its evaluation is documented in SER Section 3.0.3.2.5. The staff notes that the Fire Protection Program manages the aging effects for (1) fire barriers by performing visual inspection, (2) the diesel driven fire pumps' fuel supply lines through performance testing, and (3) the external surfaces of the halon and CO 2 systems through visual inspection. However, the staff also notes that the description of the Fire Protection Program does not include criteria for inspections of the internal surfaces of components or leakage testing which could detect loss of material, which is included in the GALL Report recommended AMP. It is not clear to the staff how the Fire Protection Program is adequate to manage loss of material for these components exposed internally to wetted air or gas. By letter dated June 25, 2010 , the staff issued RAI 3.3.2.12-02 requesting that the applicant justify how the Fire Protection Program will adequately manage loss of material due to pitting and crevice corrosion for the components exposed to an internal environment of wetted air or gas. In its response dated July 21, 2010, the applicant stated that the Fire Protection Program includes inspections of all fire dampers with fusible links at least once every 18 months, but that in order to ensure fire dampers that do not have fusible links are properly inspected, additional line items must be added to the LRA. The applicant revised LRA Table 3.3.2-12 to include two additional line items for galvanized steel damper housings exposed internally to wetted air or gas, which are being managed for loss of material due to general, pitting, and crevice corrosion by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, reference item 3.3.1
-72, and cite generic note A. The applicant also revised LRA Section B.2.1.15 to clarify that all fire dampers equipped with fusible links, which penetrate fire barriers, are to be visually inspected at least once per refueling cycle (18 months) and functionally tested, as required. The staff confirmed that the Fire Protection Program inclu des activities to inspect fire dampers with fusible links at least once every 18 months. The staff finds the applicant's response to RAI 3.3.2.12-02 and its use of the aforementioned programs to manage aging for fire dampers with and without fusible links exposed to internal condensation acceptable because each program includes visual inspections of fire dampers which are appropriate for detecting loss of material and are consistent with the inspection methods in the GALL Report recommended AMP.
The staff concludes that 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 Aging Management Review Results 3-328 consistent with the CLB during the period of extended operation, as required by 10 C FR 54.21(a)(3).
3.3.2.1.12 Loss of Material Due to General, Pitting, Crevice, Galvanic, 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, crevice, galvanic, and microbiologically
-influenced corrosion and fouling. The LRA credits the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage the aging effect for carbon steel piping and fittings in Table 3.3.2-17. The GALL Report recommends GALL AMP XI.M20, "Open
-Cycle Cooling Water System," to ensure that these aging effects are adequately managed. The associated AMR line item cites generic note E. For the line item associated with generic note E, GALL AMP XI.M20 visually monitors the condition of the open
-cycle cooling water system components and their coated surfaces exposed to a water environment for loss of material. In addition, when necessary, the program performs nondestructive (e.g., ultrasonic testing [UT], eddy current testing [ECT]) testing to measure wall thinning and preventive measures (e.g., chemical treatment, system flushing) to assure that aging effects due to MIC, biofouling, and silt are managed for safety
-related components within the scope of GL 89-13. Inspections are performed annually or during refueling outages. In its review of components associated with item 3.3.1
-77, 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 aging of the referenced carbon steel heat exchanger components through visual inspections during surveillances, maintenance activities, and outages. When the inspections yield evidence for loss of material or fouling that could potentially impair these components' intended function, then the applicant stated it evaluates the degraded components and, if warranted, implements its corrective action program. The staff's evaluation of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is documented in SER Section 3.0.3.1.15. The staff notes that the performance of periodic visual inspections, further evaluation of potentially impaired components, and application of the corrective action program for degraded components implemented by the Inspection of Surfaces in Miscellaneous Piping and Ducting Components Program provides similar detection as GALL AMP XI.M20. In its review of components associated with item 3.3.1
-77, 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 (1) the components being managed by the program are nonsafety
-related and not within the scope of GL 89
-13, therefore, the preventive measures in GALL AMP XI.M20 are not appropriate; and (2) its visual inspections are as comprehensive as the GALL AMP XI.M20 inspections for this nonsafety
-related item.
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, crevice, galvanic, and microbiologically
-influenced corrosion and fouling. The LRA credits the Fire Water System Program to manage aging for steel piping and fittings in the fire protection system. The GALL Report recommends GALL AMP XI.M20, "Open
-Cycle Cooling Water System," to ensure that these aging effects are adequately managed. The AMR line items cite generic note E. The AMR line items also cite plant
-specific Note 5, indicating that the Fire Water System Program is Aging Management Review Results 3-329 substituted to manage the aging effects applicable to this component type, material, and environment combination.
The staff reviewed the applicant's Fire Water System Program and its evaluation is documented in SER Section 3.0.3.2.6. In its review of components associated with Table 3.3-1, item 3.3.1-77, the staff notes that, in LRA Table 3.3.2-12, the applicant referenced GALL Report item VII.C1
-5, which is for steel heat exchanger components exposed to raw water in the open-cycle cooling water system (service water system). The staff reviewed the GALL Report and noted that item VII.G
-24 is for steel piping, piping components, and piping elements exposed to raw water in the fire protection system with the same aging effects and would have been a more appropriate reference, along with a reference to LRA Table 3.3.1, item 3.3.1
-68. This GALL Report item recommends the Fire Water System Program to manage loss of material due to general, pitting, crevice, galvanic, and microbiologically
-influenced corrosion and fouling of steel piping and piping components exposed to raw water. The staff finds the applicant's program acceptable to manage aging for these components because (1) it includes functional testing, flow testing, and volumetric examinations to detect loss of material; and (2) the program is consistent with the GALL Report recommendations in item VII.G
-24 for this material, environment, and aging effect combination.
The staff concludes that 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).
3.3.2.1.13 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 alloy piping, piping components, and piping elements exposed to raw water for loss of material due to pitting, crevice, and microbiologically
-influenced corrosion. The LRA credits the Periodic Inspection Program to manage aging effects for stainless steel heat exchangers and components, pump casings, piping and fittings, valve bodies, flow elements, hoses, thermowell, filter housing, orifices, and tanks in Tables 3.3.2-5, 3.3.2-17, and 3.3.2
-21. The GALL Report recommends GALL AMP XI.M20, "Open
-Cycle Cooling Water System," to ensure that these aging effects are adequately managed. The associated AMR line items cite generic note E. For those line items associated with generic note E, the GALL AMP XI.M20 recommends preventive measures including proper selection of materials and coatings, periodic flushes and cleaning, and raw water chemistry control, as well as visual inspections and nondestructive examinations (NDE) or condition monitoring of components exposed to open
-cycle cooling water. Open
-cycle cooling water is water that transfers heat from safety
-related components to the ultimate heat sink. In its review of the LRA of components associated with item 3.3.1
-80, for which the applicant cited generic note E, the staff notes that the Periodic Inspection Program proposes to manage the aging effects of stainless steel heat exchangers and components, pump casings, piping and fittings, valve bodies, flow elements, hoses, thermowell, filter housing, orifices, and tanks exposed to raw water for loss of material due to pitting, crevice, and microbiologically
-influenced corrosion and fouling.
The staff's evaluation of the applicant's Periodic Inspection Program is documented in SER Section 3.0.3.3.2. The staff notes that the Periodic Inspection Program includes periodic visual inspections of components and ultrasonic wall thickness measurements of piping and its components to detect loss of material due to pitting, crevice, and microbiologically
-influenced Aging Management Review Results 3-330 corrosion. The staff also notes that the referenced components in the component cooling, heating water and heating steam, and radwaste systems are nonsafety
-related, and in accordance with NUREG
-1833, "Technical Bases for Revision to the License Renewal Guidance Documents," use of a substitute program for the "Open
-Cycle Cooling Water" program is appropriate provided it has the same inspection procedures and provides reasonable assurance that the components' intended functions will be maintained within the CLB for the period of extended operation. In its review of components associated with item 3.3.1-80, the staff finds the applicant's Periodic Inspection Program acceptable to manage aging effects for these components because it performs similar periodic visual inspections and wall thickness measurements that are appropriate to detect loss of material, thinning, and fouling.
The staff concludes that 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).
3.3.2.1.14 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 alloy piping, piping components, and piping elements exposed to raw water for loss of material due to pitting, crevice, and microbiologically
-influenced corrosion and fouling. The LRA credits the Periodic Inspection Program to manage the aging effect for copper
-Zinc alloyed piping and fittings and valve bodies exposed to raw water in Table 3.3.2-13. The GALL Report recommends GALL AMP XI.M20, "Open-Cycle Cooling Water System," to ensure that these aging effects are adequately managed. The associated AMR line item cites generic note E. For those line items associated with generic note E, GALL AMP XI.M20 recommends preventive measures including proper selection of materials and coatings, periodic flushes and cleaning, and raw water chemistry control, as well as visual inspections and NDE testing for condition monitoring of components exposed to open
-cycle cooling water. Open
-cycle cooling water is water that transfers heat from safety
-related components to the ultimate heat sink. In its review of the LRA of components associated with item 3.3.1-81 for which the applicant cited generic note E, the staff noted that the Periodic Inspection Program proposes to manage the aging effects of copper
-Zinc alloy piping, fittings, and valve bodies exposed to raw water with visua l and volumetric inspection methods for loss of material and fouling that could result in reduction of heat transfer.
The staff's evaluation of the applicant's Periodic Inspection Program is documented in SER Section 3.0.3.3.2. The staff notes that the Periodic Inspection Program includes periodic visual inspections of components and ultrasonic wall thickness measurements of piping and its components to detect loss of material and fouling. The staff also notes that components included in item 3.3.1-81 made of copper with less than 15 percent Zinc are resistant to SCC, selective leaching, and pitting and crevice corrosion. The staff further notes that the referenced components in the fresh water system are not safety
-related and in accordance with NUREG-1833, "Technical Bases for Revision to the License Renewal Guidance Documents," use of a substitute program for the "Open
-Cycle Cooling Water" program is appropriate provided it has the same inspection procedures and provides a reasonable assurance that th e components' intended functions will be maintained within the CLB for the period of extended operation. In its review of components associated with item 3.3.1-81, the staff finds the applicant's proposal to manage aging using the Periodic Inspection Program acceptable Aging Management Review Results 3-331 because it includes similar periodic visual inspections of components and ultrasonic wall thickness measurements of piping and its components to detect loss of material, thinning, and fouling.
The staff concludes that 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).
3.3.2.1.15 No Aging Effect Requiring Management LRA Table 3.3.1, item 3.3.1
-98 addresses steel, stainless steel, and copper alloy piping, piping components, and piping elements exposed to dried air, which have no AERM. The LRA credits the Compressed Air Monitoring Program to manage the aging effect. Although the GALL Report recommends that no AMP is needed to ensure that these aging effects are adequately managed, the applicant credits the Compressed Air Monitoring Program to further verify that conditions do not change which could result in AERMs. The associated AMR line items cite generic note E, indicating that the LRA AMR is consistent with the GALL Report item for material, environment, but a different AMP is credited. Line items associated with steel, stainless steel, and copper alloy piping, piping components, and piping elements exposed to dry air in Table 3.3.2-6 also cite plant
-specific Note 1, which states that "the Compressed Air Monitoring Program is substituted to manage the aging effect(s) applicable to this component type, material, and environment combination. The Compressed Air Monitoring Program is applied to confirm the internal environment remains sufficiently dry to preclude aging effects."
The staff's evaluation of the applicant's Compressed Air Monitoring Program is documented in SER Section 3.0.3.1.10. The staff notes that GALL Report item 3.3.1
-98 does not recommend an AMP to manage steel, stainless steel, and copper alloy piping, piping components, and piping elements exposed to dried air because there is not an AERM. The staff also notes that although no aging effect exists for this component, material, and environment combination, the applicant is crediting the Compressed Air Monitoring Program to verify the internal dry air or gas environment to ensure there are no AERMs. The staff further notes that the applicant includes line items to manage the loss of material due to pitting and crevice corrosion aging effects for steel, stainless steel, and copper alloy piping, piping components, and piping elements exposed to wet air, which also credits the Compressed Air Monitoring Program. In its review of components associated with item 3.3.1-98, the staff finds the applicant's proposal to manage aging using the Compressed Air Monitoring Program acceptable because (1) there is no AERM for this component, material, and environment combination; (2) although the GALL Report recommends that no AMP is needed to ensure these aging effects are adequately managed, the applicant credits the Compressed Air Monitoring Program to further verify that conditions do not change which could result in AERMs; and (3) if conditions do change and the environment becomes wet air as opposed to dry air, the applicant has identified additional line items to manage the loss of material due to pitting and crevice corrosion aging effects, which are managed by the Compressed Air Monitoring Program.
The staff concludes that 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).
 
Aging Management Review Results 3-332 3.3.2.1.16 Loss of Material Due to Pitting, Crevice, and Microbiologically
-Influenced Corrosion and Fouling LRA Table 3.4.1, item 3.4.1-33 addresses stainless steel heat exchanger components exposed to raw water for loss of material due to pitting, crevice, and microbiologically
-influenced corrosion and fouling. The LRA credits the Periodic Inspection Program to manage aging effects for stainless steel pump casings, piping and fittings, valve bodies, and a sump screen in Tables 3.3.2-20 and 3.5.2
-3. The GALL Report recommends GALL AMP XI.M20, "Open
-Cycle Cooling Water System," to ensure that these aging effects are adequately managed.
The associated AMR line item cites generic note E. For those line items associated with generic note E, GALL AMP XI.M20 recommends preventive measures including proper selection of materials and coatings, periodic flushes and cleaning, and raw water chemistry control, as well as visual inspections and NDE testing for condition monitoring of components exposed to open
-cycle cooling water. Open
-cycle cooling water is water that transfers heat from safety
-related components to the ultimate heat sink. In its review of the LRA of components associated with item 3.4.1-33 for which the applicant cited generic note E, the staff notes that the Periodic Inspection Program proposes to manage the aging effects of stainless steel pump casings, piping and fittings, valve bodies, and a sump screen exposed to raw water for loss of material due to pitting, crevice, and microbiologically
-influenced corrosion and fouling.
The staff's evaluation of the applicant's Periodic Inspection Program is documented in SER Section 3.0.3.3.2. The staff notes that the Periodic Inspection Program includes periodic visual inspections of components and ultrasonic wall thickness measurements of piping and its components to detect loss of material due to pitting, crevice, and microbiologically-influenced corrosion and fouling. The staff also notes that the equipment for floor drainage and radwaste systems and containment structure do not contain safety
-related components exposed to open-cycle cooling water, so the use of the Open
-Cycle Cooling Water Program would not be appropriate. In its review of components associated with item 3.4.1-33, the staff finds the applicant's Periodic Inspection Program acceptable to manage aging for these components because it performs similar periodic visual inspections and wall thickness measurements that are appropriate to detect loss of material, thinning, and fouling.
The staff concludes that 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).
3.3.2.1.17 Conclusion for AMRs Consistent with the GALL Report The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing the associated aging effects. On the basis of its review, the staff concludes that the AMR results, which the applicant claimed to be consistent with the GALL Report, are consistent with the GALL Report AMRs. Therefore, the staff concludes that the applicant has demonstrated that the aging effects for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
Aging Management Review Results 3-333 3.3.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended LRA Section 3.3.2.2 provides further evaluation of aging management, as recommended by the GALL Report, for the auxiliary systems components. The applicant provided information concerning how it will manage the following aging effects:
cumulative fatigue damage reduction of heat transfer due to fouling cracking due to SCC cracking due to SCC and cyclic loading hardening and loss of strength due to elastomer degradation reduction of neutron
-absorbing capacity and loss of material due to general corrosion loss of material due to general, pitting, and crevice corrosion loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion  loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion 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 microbiologically
-influenced corrosion loss of material due to wear loss of material due to cladding breach QA for aging management of nonsafety
-related components For component groups evaluated in the GALL Report for which the applicant claimed consistency with the GALL Report and for which the GALL Report recommends further evaluation, the staff audited and reviewed the applicant's evaluations to determine whether they adequately address those issues. In addition, the staff reviewed the applicant's further evaluations against the criteria 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
 
Aging Management Review Results 3-334 LRA Section 3.3.2.2.1 states fatigue is a TLAA as defined in 10 CFR 54.3. Furthermore, TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c). The applicant stated that the evaluation of metal fatigue as a TLAA for the chemical and volume control system is discussed in LRA Section 4.3 and the evaluation of crane load cycles as a TLAA for cranes and hoists is discussed in LRA Section 4.6. 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 auxiliary systems components is a TLAA as defined in 10 CFR 54.3 and that 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 the staff's recommended acceptance criteria and review procedures for reviewing these TLAAs in SRP
-LR Section 4.3, "Metal Fatigue Analysis."  The staff also reviewed LRA Section 3.3.2.2.1 and the AMRs discussed in this Section against the staff's AMR items for evaluating cumulative fatigue damage in PWR auxiliary designs, as given in AMR items 1 and 2 of the GALL Report, Volume 1, Table 3 and the AMR items in Section VII of the GALL Report, Volume 2, Revision 1 that derive from these GALL Report, Volume 1 AMR items.
With regard to LRA Table 3.3.1, item 3.3.1
-1, the staff noted that GALL AMR item VII.B
-2 identifies cumulative fatigue damage as an applicable aging effect for steel cranes or structural girders exposed to air and recommends that the TLAA on metal fatigue be used to manage this aging effect. The applicant included an applicable line item in LRA Table 3.3.2-9 for steel cranes or hoists consistent with the recommendations in the SRP
-LR. Based on its review, the staff finds the applicant's AMR analysis on cumulative fatigue damage of steel cranes or structural girders to be acceptable because it is consistent with the recommendations in SRP-LR Section 3.3.2.2.1. The staff evaluates the TLAA analysis for the steel cranes or hoists in SER Section 4.6. With regard to LRA Table 3.3.1, item 3.3.1
-2, the staff notes that GALL AMR items VII.E1
-4, VII.E1-16, VII.E1
-18, VII.E3
-14, and VII.E3
-17 identifies cumulative fatigue damage as an applicable aging effect for heat exchangers and piping, piping components, and piping elements and recommends that the TLAA on metal fatigue be used to manage this aging effect. The applicant included an applicable line item in LRA Table 3.3.2-2 for heat exchanger components, piping, fittings, and tanks that received implicit fatigue analysis calculations in accordance with design code requirements for ASME Code Section III Class 2 or 3 components or ANSI B31.1 components consistent with the recommendations in the SRP-LR. Based on its review, the staff finds the applicant's AMR analysis on cumulative fatigue damage of piping, piping components, piping elements, and heat exchanger components to be acceptable because it is consistent with the recommendations in SRP
-L R Section 3.3.2.2.1. The staff evaluates the TLAA analysis for the heat exchanger components, piping, fittings, and tanks in SER Section 4.3.3. Based on the programs identified, the staff concludes that the applicant has 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 determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.2.2  Reduction of Heat Transfer Due to Fouling LRA Section 3.3.2.2.2, associated with LRA Table 3.3.1, item 3.3.1-3, addresses reduction in heat transfer due to fouling in stainless steel heat exchanger tubes exposed to treated water.
Aging Management Review Results 3-335 The applicant stated that this line item is not applicable because these components will be managed by Table 3.4.1 item 3.4.1-9. The staff notes that this proposed item is associated with the further evaluation in SRP
-LR Section 3.4.2.2.4 item 1, which addresses reduction in heat transfer due to fouling in stainless steel and copper alloy heat exchanger tubes exposed to treated water in the steam and power conversion systems. The staff also notes that the applicant is proposing to use the Water Chemistry and One
-Time Inspection programs to manage aging for these components. The staff further noted that the proposed line item, 3.4.1-9, encompasses the same materials, components, environment, and aging effect and utilizes the same AMPs as line item 3.3.1-3 and, therefore, finds the applicant's determination acceptable.
Based on a review of the programs identified above, the staff concludes that the applicant's programs meet SRP
-LR Section 3.3.2.2.2. For those line items that apply to LRA Section 3.3.2.2.2, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.2.3  Cracking Due to Stress
-Corrosion Cracking The staff reviewed LRA Section 3.3.2.2.3 against the criteria in SRP-LR Section 3.3.2.2.3.
  (1) LRA Section 3.3.2.2.3 addresses cracking due to SCC, stating that this aging effect is not applicable to Salem, which are PWRs.
SRP-LR Section 3.3.2.2.3 states that cracking due to SCC could occur in the stainless steel piping, piping components, and piping elements of the BWR standby liquid control system that are exposed to sodium pentaborate solution greater than 60 C (140 &deg;F).
This line item is not applicable to Salem because Salem units are PWRs. On this basis , the staff finds that the SRP
-LR criteria do not apply to Salem.
  (2) LRA Section 3.3.2.2.3, item 2 is referenced by 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 60 C (140 &deg;F), which are being managed for cracking due to SCC by the Water Chemistry Program. The applicant addressed the further evaluation criteria of the SRP
-LR by stating that this item is not applicable to auxiliary systems because this component, material, environment, and aging effect/mechanism for auxiliary system components are managed within item 3.3.1-90 and uses the Water Chemistry Program to manage the aging effects.
The staff reviewed LRA Section 3.3.2.2.3, item 2 against the criteria in SRP
-LR Section 3.3.2.2.3, item 2, which states that cracking due to SCC could occur in stainless steel and stainless clad steel heat exchanger components exposed to treated water greater than 60 C (140 &deg;F). The SRP
-LR also states that the GALL Report recommends further evaluation of a plant
-specific AMP and that the acceptance criteria are described in Branch Technical Position RLSB
-1. In its review of components associated with item 3.3.1-5, the staff notes the applicant relies on the Water Chemistry Program alone, whereas a plant
-specific program in accordance with SRP
-LR Appendix A.1 has a detection of aging effects program element which is not addressed in the Water Chemistry Program. By a June 11, 2010 Aging Management Review Results 3-336 letter, the staff issued R AI 3.3.2.2-3 requesting that the applicant identify the method that will be used to detect cracking or provide justification for not performing activities that will detect cracking due to SCC in these components.
In its July 8, 2010 response, the applicant stated that the further evaluation in Section 3.3.2.2.3, item 2 incorrectly referenced item 3.3.1-90, which is for components exposed to treated borated water. The applicant also stated that the associated components in auxiliary systems, which align with item 3.3.1-5, have been evaluated with the steam and power conversion systems through item 3.4.1-14 and associated Section 3.4.2.2.6. The applicant further stated that the programs to detect cracking for these components are the Water Chemistry and One
-Time Inspection programs and that the LRA will be revised to indicate that there are no stainless steel heat exchanger components in the associated environment evaluated in auxiliary systems.
The staff finds the applicant's response acceptable because it corrected the inaccurate information in the LRA and notes that SRP
-LR Section 3.4.2.2.6, which is referenced by item 3.4.1-14, recommends the same AMPs as those being proposed above by the applicant. The staff's review of LRA Sections 2.3.3 and 3.3 confirmed that the in
-scope stainless steel and stainless clad steel heat exchanger components exposed to treated water greater than 60 C (140 &deg;F) present in the auxiliary systems have been evaluated through item 3.4.1-14. The staff's concern described in RAI 3.3.2.2-3 is resolved and the staff finds the applicant's determination, that this item is not applicable, to be acceptable because the applicant provided further evaluation through the comparable item 3.4.1-14.  (3) LRA Section 3.3.2.2.3.3 is referenced by LRA Table 3.3.1, item 3.3.1
-6 and addresses stainless steel diesel engine exhaust expansion joints exposed to diesel exhaust, which are being managed for SCC by the Periodic Inspection Program. The applicant addressed the further evaluation criteria of the SRP
-LR by stating that the program includes focused visual inspections to evaluate if material degradation is occurring, which could result in a loss of component intended function, due to exposure to the environmental condition.
The staff reviewed LRA Section 3.3.2.2.3.3 against the criteria in SRP
-LR Section 3.3.2.2.3, item 3, which states that cracking due to SCC could occur in stainless steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust. The SR P-LR recommends a plant
-specific AMP to manage SCC. In addition, a further evaluation of the plant
-specific program for these components is recommended to ensure that the aging effect is adequately managed. GALL Report item VII.H2
-1 (AP-33) also recommends further evaluation of a plant
-specific AMP to ensure that the aging effect is adequately managed. The acceptance criteria for further evaluation of the plant
-specific AMP are described in Branch Technical Position RSLB
-1. The staff's evaluation of the applicant's Periodic Inspection Program is documented in SER Section 3.0.3.3.2. The staff notes that the program is acceptable because it requires focused visual inspections to ensure that the existing environmental conditions are not causing environmental degradation that could result in a loss of the component's intended function. In its review of components associated with item 3.3.1
-6, the staff finds the applicant's proposal to manage aging using the Periodic Inspection Program acceptable because it satisfies the acceptance criteria in SRP
-LR Section 3.3.2.2.3, item 3 by requiring visual inspection techniques which will be able to detect SCC.
 
Aging Management Review Results 3-337  Based on the program identified, the staff concludes that the applicant's program meets SRP-LR Section 3.3.2.2.3.3 criteria. For those line items that apply to LRA Section 3.3.2.2.3.3, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
Based on a review of the programs identified above, the staff concludes that the applicant's programs meet SRP
-LR Section 3.3.2.2.3. For those line items that apply to LRA Section 3.3.2.2.3, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended 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 criteria in SRP
-LR Section 3.3.2.2.4.
  (1) LRA Section 3.3.2.2.4, item 1 is referenced by LRA Table 3.3.1, item 3.3.1-7 and addresses stainless steel PWR non
-regenerative heat exchanger components exposed to borated water, which are being managed by the Water Chemistry Program.
The applicant addressed the further evaluation criteria of the SRP
-LR by stating that the Water Chemistry Program, in conjunction with continuous monitoring for radioactivity on the shell side of the non
-regenerative stainless steel heat exchangers, will be used to manage this aging effect.
The staff reviewed LRA Section 3.3.2.2.4, item 1 against the criteria in SRP
-LR Section 3.3.2.2.4, item 1, which states that cracking due to SCC and cyclic loading could occur in stainless steel PWR non
-regenerative heat exchanger components exposed to treated borated water greater than 60 C (140 &deg;F) in the chemical and volume control system. The SRP
-LR also states that the existing AMP relies on monitoring and control of primary water chemistry in PWRs to manage the aging effects of cracking due to SCC and that the effectiveness of the water chemistry control program should be verified to ensure that cracking does not occur. The SRP
-LR further states that an acceptable verification program includes temperature and radioactivity monitoring of the shell side water and ECT of tubes.
In its review of components associated with item 3.3.1-7, the staff notes the applicant relies on continuous monitoring for radioactivity on the shell side of the non
-regenerative stainless steel heat exchangers to detect cracking due to SCC and cyclic loading and that this will not detect cracking before it has progressed through
-wall, whereas the GALL Report recommends eddy current examination which would detect cracking before leakage occurs. By a June 17, 2010 letter, the staff issued RAI 3.3.2.2-1 requesting that the applicant identify the method that will be used to detect cracking before leakage occurs. In its July 15, 2010 response, the applicant stated that the LRA will be revised to add the One-Time Inspection Program for verifying the effectiveness of the Water Chemistry Program for the associated components. The applicant also stated that the One
-Time Inspection Program will be revised to include ECT of stainless steel tubes in a non-regenerative heat exchanger normally exposed to treated borated water greater Aging Management Review Results 3-338 than 60 C (140 &deg;F). The staff finds the applicant's response acceptable because the inclusion of ECT of the associated components in the One
-Time Inspection Program will be able to verify the effectiveness of the Water Chemistry Program by identifying cracking prior to the loss of intended function (pressure boundary). The staff's concern described in RAI 3.3.2.2-1 is resolved.
The staff's evaluation of the applicant's Water Chemistry and One
-Time Inspection programs is documented in SER Sections 3.0.3.1.2 and 3.0.3.1.11, respectively. The staff finds the applicant's proposal to manage aging using the above programs acceptable because (1) the Water Chemistry Program provides for periodic sampling to maintain contaminants at acceptable limits to mitigate cracking due to SCC and cyclic loading, and (2) the One-Time Inspection Program will verify the effectiveness of the Water Chemistry Program by performing ECT of stainless steel tubes in a non-regenerative heat exchanger.
Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.4 item 1 criteria. For those line items that apply to LRA Section 3.3.2.2.4 item 1, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
  (2) LRA Section 3.3.2.2.4, item 2 is referenced by LRA Table 3.3.1, item 3.3.1-8 and addresses stainless steel PWR regenerative heat exchanger components exposed to borated water, which are being managed for cracking due to SCC and cyclic loading. The applicant addressed the further evaluation criteria of the SRP
-LR by stating that the Water Chemistry Program will manage this aging effect in the chemical and volume control system and that the integrity of the regenerative heat exchanger is verified by continuous temperature monitoring. The applicant also stated that the One-Time Inspection Program includes inspections of other stainless steel components in this environment to verify the effectiveness of the Water Chemistry Program to manage cracking. The staff reviewed LRA Section 3.3.2.2.4, item 2 against the criteria in SRP
-LR Section 3.3.2.2.4, item 2, which states that cracking due to SCC and cyclic loading could occur in stainless steel PWR regenerative heat exchanger components exposed to treated borated water greater than 60 C (140 &deg;F). The SRP
-LR also states that the existing AMP relies on monitoring and controlling primary water chemistry to manage this aging effect and that the effectiveness of the water chemistry control program should be verified to ensure that cracking does not occur. The SRP
-LR further states that the GALL Report recommends a plant
-specific AMP be evaluated to verify the absence of this aging effect and that acceptance criteria are described in Branch Technical Position RLSB-1. In its review of components associated with item 3.3.1-8, the staff notes that the applicant is using the One
-Time Inspection Program in lieu of a plant
-specific program where periodic inspections are to be scheduled and that generic note A is assigned to the one-time inspection for the regenerative heat exchangers. By a June 17, 2010 letter, the staff issued RAI 3.3.2.2-2 requesting that the applicant provide justification for using a one-time inspection in lieu of periodic inspections in a plant
-specific program and the use of generic note A instead of generic note E when applying the One
-Time Inspection Program to verify the effectiveness of the Water Chemistry Program.
 
Aging Management Review Results 3-339  In its July 15, 2010 response, the applicant discussed the all
-welded construction of the regenerative heat exchangers which prevents access to the internals without cutting and stated that the One
-Time Inspection Program includes an inspection of a non-regenerative heat exchanger. The applicant also stated that a search of plant operating experience had not found any instances of tube leakage for the regenerative heat exchanger and that the One
-Time Inspection Program provides the means to verify the effectiveness of the Water Chemistry Program without excessive radiological dose that the Periodic Inspection Program would require. The applicant further stated that generic note A was inadvertently used in conjunction with the One
-Time Inspection Program and it revised the designation to generic note E. The staff finds the applicant's response acceptable because, as discussed in GALL AMP XI.M32, "One
-Time Inspection," a one
-time inspection can be used to verify the system-wide effectiveness of an AMP that controls water chemistry, and the eddy current inspection of a non
-regenerative heat exchanger in a similar environment will confirm that this aging effect is being adequately managed by the Water Chemistry Program. In addition, the applicant will correct the inadvertent use of generic note A for this item by revising the LRA to designate generic note E. The staff's concern described in RAI 3.3.2.2-2 is resolved.
The staff's evaluation of the applicant's Water Chemistry and One
-Time Inspection programs is documented in SER Sections 3.0.3.1.2 and 3.0.3.1.11, respectively. The staff finds the applicant's proposal to manage aging using the above programs acceptable because (1) the Water Chemistry Program provides for periodic sampling to maintain contaminants at acceptable limits to mitigate cracking due to SCC, and (2) cyclic loading and the One
-Time Inspection Program will verify the effectiveness of the Water Chemistry Program by performing ECT of stainless steel tubes in a similar environment in a non
-regenerative heat exchanger.
Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.4, item 2 criteria. For those line items that apply to LRA Section 3.3.2.2.4, item 2, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CF R 54.21(a)(3).
  (3) LRA Section 3.3.2.2.4.3 refers to Table 3.3.1, item 3.3.1
-9 and addresses cracking due to SCC and cyclic loading for the stainless steel high
-pressure pump casings in the chemical and volume control system exposed to treated borated water. The LRA also states that the Water Chemistry Program and One
-Time Inspection Program will be implemented to manage the aging effect. The LRA further states that the Water Chemistry Program includes activities for monitoring and controlling the primary water chemistry.
The staff reviewed LRA Section 3.3.2.2.4.3 against the criteria in SRP
-LR Section 3.3.2.2.4.3, which states that cracking due to SCC and cyclic loading could occur for the stainless steel pump casing for the PWR high-pressure pumps in the chemical and volume control system. The SRP
-LR also states that the existing AMP relies on monitoring and control of the primary water chemistry to manage the aging effects of cracking due to SCC. The SRP
-LR further states that the effectiveness of the water chemistry control program should be verified to ensure that cracking does not occur. The staff also noted that the GALL Report, under item VII.E1
-7, recommends the Aging Management Review Results 3-340 water chemistry program to manage the aging effect. As the SRP
-LR indicates, the GALL Report further recommends that a plant
-specific program be evaluated to verify the absence of cracking due to SCC and cyclic loading.
The staff reviewed the LRA and identified in Table 3.1.1, item 3.1.1
-9 and Table 3.3.2-2 that the applicant credited the Water Chemistry Program and One
-Time Inspection Program to manage the cracking due to SCC and cyclic loading in the stainless steel pump casing. The staff also reviewed the applicant's Water Chemistry Program and One-Time Inspection Program. The staff's evaluations are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.11, respectively. The applicant indicated that the One-Time Inspection Program includes a one
-time inspection of more susceptible materials in potentially more aggressive environments to manage the aging effect. The staff finds that the credited programs are adequate to manage the aging effect because (1) the Water Chemistry Program monitors the water chemistry control parameters against the established parameter limits and, if a parameter exceeds the limit, the program performs adequate actions such that the water chemistry control continues to mitigate the aging effect; (2) the One
-Time Inspection Program includes a one-time inspection of selected components to verify the effectiveness of the Water Chemistry Program; and (3) the one
-time inspection can ensure that significant degradation does not occur and the component's intended function is maintained during the period of extended operation. On the basis of its review, the staff finds that the applicant's AMR results are consistent with those under GALL Report, Volume 2, item VII.E1-7 and the applicant satisfied the acceptance criteria in SPR
-LR Section 3.3.2.2.4.3.
Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.4 criteria. For those items that apply to LRA Section 3.3.2.2.4, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended 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 stress corrosion cracking and cyclic loading in high strength bolting exposed to air with steam or water leakage. The applicant stated that this line item is not applicable because there is no high
-strength steel closure bolting exposed to air with steam or water leakage. 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 systems and, therefore, finds the applicant's determination acceptable.
Based on a review of the programs identified above, the staff concludes that the applicant's programs meet SRP
-LR Section 3.3.2.2.4 criteria. For those line items that apply to LRA Section 3.3.2.2.4, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.2.5  Hardening and Loss of Strength Due to Elastomer Degradation (1) LRA Section 3.3.2.2.5.1 refers to LRA Table 3.3.1, item 3.3.1
-11 and addresses elastomer components (door seals and flexible connections) in the auxiliary building Aging Management Review Results 3-341 ventilation, containment ventilation, control area ventilation, fuel handling ventilation, and switchgear and penetration area ventilation systems exposed to indoor air, which are being managed for hardening and loss of strength by the Periodic Inspection Program. The applicant addressed the further evaluation requirement by stating that the Periodic Inspection Program is used to manage aging effects of components that are not covered by other AMPs, including external and internal surfaces of non
-steel components. The applicant also stated that the Periodic Inspection Program includes visual inspections and physical manipulation of elastomer components.
The staff reviewed LRA Section 3.3.2.2.5.1 against the criteria in SRP-LR Section 3.3.2.2.5.1, which states that hardening and loss of strength could occur for elastomer seals and components exposed to uncontrolled indoor air. The GALL Report recommends further evaluation of a plant
-specific AMP to ensure that these aging effects are adequately managed.
The staff reviewed the applicant's Periodic Inspection Program and its evaluation is documented in SER Section 3.0.3.3.2. In its review of components associated with LRA item 3.3.1
-11 for which the applicant assigned generic note E, the staff notes that the Periodic Inspection Program is a plant
-specific program that proposes to detect the aging of elastomer door seals and flexible connections through the use of visual inspections and physical manipulations. The staff finds the applicant's proposal to manage aging using the Periodic Inspection Program acceptable because (1) the program performs visual inspections and physical manipulations that are capable of detecting hardening and loss of strength in elastomer components, and (2) the program initiates corrective actions, implemented through the applicant's corrective program, if indications of age
-related degradation are found.
Based on the program identified, the staff concludes that the applicant's program meets
 
SR P-LR Section 3.3.2.2.5.1 criteria. For those line items that apply to LRA Section 3.3.2.2.5.1, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
(2) LRA Section 3.3.2.2.5 Item 2, associated with LRA Table 3.3.1, item 3.3.1
-12, addresses hardening and loss of strength due to elastomer degradation in elastomer linings of the filters, valves, and ion exchangers in spent fuel pool cooling and cleanup systems exposed to treated water or to treated borated water. The applicant stated that this line item is not applicable because there are no elastomer lining components exposed to treated water that are subject to hardening and loss of strength due to elastomer degradation in the Auxiliary Systems. The staff reviewed LRA Sections 2.3.3 and 3.3, and UFSAR and confirmed that no elastomer linings of the filters, valves, and ion exchangers in spent fuel pool cooling and cleanup systems exposed to treated water or to treated borated water within scope are present in the Auxiliary Systems and, therefore, finds the applicant's determination acceptable.
Based on a review of the programs identified above, the staff concludes that the applicant's programs meet SRP
-LR Section 3.3.2.2.5 criteria. For those line items that apply to LRA Section 3.3.2.2.5, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the Aging Management Review Results 3-342 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 LRA Section 3.3.2.2.6, referenced by LRA Table 3.3.1, item 3.3.1
-13, addresses reduction of neutron-absorbing capacity and loss of material due to general corrosion in neutron
-absorbing Boral spent fuel storage racks exposed to treated or borated water, which are being managed by the Boral Monitoring Program. The applicant addressed the further evaluation criteria of the SRP-LR by stating that the plant
-specific Boral Monitoring Program is used to mitigate reduction of neutron
-absorbing capacity and loss of material aging effects. The applicant stated that the Water Chemistry Program will manage loss of material of the aluminum cladding of the Boral.
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 Branch Technical Position RLSB
-1. The staff's evaluation of the applicant's Boral Monitoring Program is documented in SER Section 3.0.3.3.5. 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 and Water Chemistry Programs acceptable because (1) the Water Chemistry Program is consistent with the GALL Report recommendations, and (2) the Boral Monitoring Program satisfies the acceptance criteria of the SRP
-LR and uses inspection techniques (e.g., neutron attenuation, visual inspections, looking specifically for corrosion, weld cracks, or leaks) that will detect aging effects related to the neutron absorption and dimensional integrity.
Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.6 criteria. For those line items that apply to LRA Section 3.3.2.2.6, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended 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 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 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 through examination of susceptible locations in steel piping, piping components, piping elements, tanks, and heat exchangers exposed to lubricating oil.
Aging Management Review Results 3-343  LRA Section 3.3.2.2.7.1, referenced by LRA Table 3.3.1, item 3.3.1
-15, addresses steel RCP oil collection system piping, tubing, and value bodies 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 through examination of susceptible locations in the RCP oil collection system steel piping exposed to lubricating oil in the fire protection system.
LRA Section 3.3.2.2.7.1, referenced by LRA Table 3.3.1, item 3.3.1
-16, addresses the steel RCP oil collection system tank exposed to lubricating oil, which is 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 through the examination of susceptible locations in the RCP oil collection system steel tank exposed to lubricating oil in the fire protection 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 RCP oil collection system, exposed to lubricating oil (as part of the fire protection system). 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 verified 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 lube oil chemistry control 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 evaluation of the applicant's Lubricating Oil Analysis and One
-Time Inspection programs is documented in SER Sections 3.0.3.2.12 and 3.0.3.1.11, respectively. In its review of components associated with items 3.3.1
-14, 3.3.1-15, and 3.3.1-16, 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 (1) the Lubricating Oil Analysis Program was determined to be consistent with the GALL Report; and (2) the applicant stated that the One
-Time Inspection Program will be used to examine steel piping, piping components, and piping elements; steel RCP oil collection system piping, tubing, and valve bodies; and the steel RCP oil collection system tank to verify the effectiveness of the Lubricating Oil Analysis Program. This satisfies the acceptance criteria in SRP
-LR Section 3.3.2.2.7, item 1 and, therefore, the applicant's AMR is consistent with GALL Report items V.A
-25, V.D1-28, VII.C1-17, VII.C2
-13, VII.E1
-19, VII.F1
-19, VII.F2
-17, VII.F3
-19, VII.F4
-15, VII.G-22, VII.H2-20, VIII.A
-14, VIII.D1
-6, VIII.E-32, VIII.G
-34, VII.G-26, and VII.G
-27. Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.7, item 1 criteria. For the line items that apply to LRA Aging Management Review Results 3-344 Section 3.3.2.2.7.1, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
  (2) LRA Section 3.3.2.2.7 addresses loss of material due to general, pitting, and crevice corrosion, stating that this aging effect is not applicable toSalem units, which are PWRs.
SRP-LR Section 3.3.2.2.7 states that loss of material due to general, pitting, and crevice corrosion may occur in steel piping, piping components, and piping elements in the BWR reactor water cleanup and shutdown cooling systems exposed to treated water.
Salem units are PWRs and do not have reactor water cleanup and shutdown cooling systems. On this basis, the staff finds that this item is not applicable to Salem.
  (3) LRA Section 3.3.2.2.7.3 refers to LRA Table 3.3.1, item 3.3.1-18 and addresses stainless steel and steel diesel engine exhaust piping and components exposed to diesel exhaust, which are being managed for loss of material due to pitting and crevice corrosion by the Periodic Inspection and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components programs. The applicant addressed the further evaluation criteria of the SRP
-LR by stating that the programs include visual inspections to evaluate if material degradation occurs with the result in a loss of component intended function, as a result of exposure to the environmental condition.
The staff reviewed LRA Section 3.3.2.2.7.3 against the criteria in SRP
-LR Section 3.3.2.2.7, item 3, which states that loss of material could occur in stainless steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust. The SRP
-LR recommends a plant
-specific AMP to manage the loss of material effect. In addition, a further evaluation of the plant
-specific program for these components is recommended to ensure that the aging effect is adequately managed. GALL Report item VII.H2
-2 (A-27) also recommends further evaluation of a plant
-specific AMP to ensure that the aging effect is adequately managed.
The acceptance criteria for further evaluation of the plant
-specific AMP are described in Branch Technical Position RSLB-1. The staff's evaluation of the applicant's Periodic Inspection and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components programs are documented in SER Section 3.0.3.3.2 and 3.0.3.1.15, respectively. The staff notes that the programs are acceptable because they require visual inspections to ensure that the existing environmental conditions are not causing environmental degradation that could result in a loss of the component's intended function. In its review of components associated with item 3.3.1
-18, the staff finds the applicant's proposal to manage aging using the Periodic Inspection and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components programs acceptable because it satisfies the acceptance criteria in SRP-LR Section 3.3.2.2.7, item 3 by requiring visual inspection techniques which will be able to detect loss of material due to pitting and crevice corrosion.
Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.7, item 3 criteria. For those line items that apply to LRA Section 3.3.2.2.7.3, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function 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 3-345 Based on a review of the programs identified above, the staff concludes that the applicant's programs meet SRP
-LR Section 3.3.2.2.7 criteria. For those line items that apply to LRA Section 3.3.2.2.7, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.2.8  Loss of Material Due to General, Pitting, Crevice, and Microbiologically
-Influenced Corrosion LRA Section 3.3.2.2.8 refers to LRA Table 3.3.1, item 3.3.1
-19 and addresses loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion in steel piping, piping components, and piping elements, with or without coating or wrapping, buried in soil, which will be managed by the Buried Piping Inspection Program. The applicant also stated that loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion in the steel penetration sleeves exposed to groundwater and soil between the containment structure and fuel handling building will be managed by the Buried Non
-Steel Piping Inspection Program. The staff reviewed LRA Section 3.3.2.2.8 against the criteria in SRP
-LR Section 3.3.2.2.8, which states that loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion could occur in steel piping, piping components, and piping elements, with or without coating or wrapping, in a soil environment. The SRP
-LR also states that the effectiveness of the buried piping and tanks inspection program should be verified to evaluate an applicant's inspection frequency and operating experience with buried components, ensuring that loss of material does not occur.
The staff reviewed the LRA AMR items associated with LRA Table 3.3.1, item 3.3.1-19 and noted that for the items that are consistent with the GALL Report for material, environment, and aging effect but a different AMP is credited (generic note E) in Tables 3.5.2-3 and 3.5.2
-5, the applicant will use the Buried Non
-Steel Piping Inspection Program to manage the loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion for the steel penetration sleeves in the containment structure and the fuel handling building. The applicant also included plant
-specific Notes 9 and 11 (depending on table number. Both of these notes state "The Buried Non
-Steel Piping Inspection Program is substituted to manage the aging effect(s) applicable for this component type, material, and environment combination. The buried carbon steel sleeve will be inspected in conjunction with the associated buried stainless steel bellows assembly located between the Fuel Handling Building and the Containment Building."  The staff further reviewed the applicant's Buried Non
-Steel Piping Inspection Program, which is evaluated in SER Section 3.0.3.3.4. The staff finds the program acceptable because in conjunction with the Buried Non
-Steel Piping Inspection Program, the applicant stated that it will perform an opportunistic or focused visual inspection of this specific component once in the 10-year period prior to the period of extended operation and once again in the first 10
-year period of extended operation, which are capable of detecting the AERM.
The staff reviewed the LRA AMR items associated with LRA Table 3.3.1, item 3.3.1-19 and notes that for the steel tanks in the fire protection system which cite generic note E in Table 3.3.2-12, the applicant will use the Aboveground Steel Tanks Program to manage the loss of material due to pitting, crevice, and microbiologically
-influenced corrosion. The staff reviewed the applicant's Aboveground Steel Tanks Program, which is evaluated in SER Section 3.0.3.2.7. The staff finds the use of the Aboveground Steel Tanks Program acceptable because it requires Aging Management Review Results 3-346 periodic visual inspections of the accessible tank outer surface and the grout or sealant at the interface between the tank base and its foundation and wall
-thickness measurements of the inaccessible tank bottom external surface by UT to ensure that the loss of material aging effect will be adequately managed and thus is consistent with GALL AMP XI.M29, "Aboveground Steel Tanks." The staff reviewed the LRA AMR items associated with LRA Table 3.3.1, item 3.3.1-19 and noted that for the steel penetration sleeves and steel piles in the service water intake which cite generic note E in Table 3.5.2-13, the applicant will use the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program to manage the loss of material due to pitting, crevice, and microbiologically
-influenced corrosion. The staff reviewed the applicant's RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program and its evaluation is documented in SER Section 3.0.3.2.16. The staff finds the use of the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program acceptable because it is designed to detect degradations and take corrective actions to ensure that the aging effects associated with water
-control structures will be adequately managed.
The staff notes that the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program is a more appropriate AMP to monitor penetration sleeves in a groundwater/soil environment because the items are not pressure boundary components; however, due to potential accessibility constraints associated with the penetration sleeves being located in a groundwater/soil environment, the staff is unclear how the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program, which is primarily a visual-based program, will be used to address the structure/aging effect combinations during the period of extended operation. By letter dated June 7, 2010, the staff issued RAI 3.5.2.1-02 requesting that the applicant describe how the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program meets or exceeds the requirements of the GALL Report recommended programs and how the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program will be used to manage carbon steel penetration sleeves in a groundwater/soil environment for loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion during the period of extended operation. The applicant was also requested to discuss surveillance and preventive measure requirements.
In its July 8, 2010 reply, the applicant stated that the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program is implemented as part of the Structures Monitoring Program, which includes periodic inspection from the indoor side of the wall of the penetration sleeves that are located below grade. The applicant also stated that the penetration sleeves are installed in concrete walls and the majority of the sleeve is located within the wall, while a small portion may protrude past the wall surface and into a soil environment. Most of the sleeve is protected on both the outer and inner surface by concrete, grout, or elastomer seal material. The applicant further stated that potential degradation of the small portion of the steel sleeve that protrudes past the exterior wall surface and is subject to the groundwater/soil environment will not impact the intended function given that most of the sleeve is protected on both the inner and outer surface and thus, degradation of this area of the sleeve is unlikely to penetrate to a wall depth sufficient to impact the intended function. The applicant stated that the Structures Monitoring Program includes inspections of the penetration seals and the associated sleeves on a 5
-year interval. These inspections will detect material degradation or indications of seal leakage prior to loss of intended function.
 
Aging Management Review Results 3-347 The staff reviewed the applicant's response and noted that the penetration sleeves are structural components embedded in concrete and that the buried portion is not reasonably accessible for inspection. Visual inspections from the inside of the wall, on a 5
-year frequency, will be able to detect degradation prior to a loss of intended function. Based on its review, the staff finds the applicant's aging management approach acceptable because the Structures Monitoring Program includes appropriate inspections to detect degradation of the penetration sleeves prior to a loss of intended function.
The staff finds the use of the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program for managing the aging effects associated with these penetration sleeves acceptable for the reasons as stated in the staff's evaluation of the applicant's response to RAI 3.5.2.1-02. The staff reviewed the LRA AMR items associated with LRA Table 3.3.1, item 3.3.1-19 and noted that for the steel piles in the containment structure, fire pump house, office building, service building, shoreline protection and dike, switchyard, and yard structures; for the steel penetration sleeves in the auxiliary building, pump tunnel, and turbine building; for the galvanized steel penetration sleeves in the turbine building; and for galvanized conduit in the switchyard which cite generic note E in Tables 3.5.2-1, 3.5.2-3, 3.5.2-4, 3.5.2-6, 3.5.2-8, 3.5.2-11, 3.5.2-14, 3.5.2-15, 3.5.2-16, and 3.5.2
-17, the applicant will use the Structures Monitoring Program to manage the loss of material due to pitting, crevice, and microbiologically
-influenced corrosion. The staff further reviewed the applicant's Structures Monitoring Program and its evaluation is documented in SER Section 3.0.3.2.15. The staff finds the use of the Structures Monitoring Program acceptable because it requires periodic sampling, testing, and analysis of groundwater chemistry and periodic inspections of the components to ensure that the aging effects will be adequately managed. The staff finds the applicant's management for loss of material due to pitting, crevice, and microbiologically
-influenced corrosion acceptable because the applicant satisfied the acceptance criteria in SPR
-LR Section 3.3.2.2.8 and, therefore, the applicant's AMR results are consistent with the one under GALL Report item VII.C1
-18. For piles as contained in the above AMR line items, LRA Section 3.5.2.2.2.2, item 3 states that:
Studies have shown that steel piles driven into undisturbed natural soil are not appreciably affected by corrosion due to the oxygen deficiency in soil at a few feet below grade. Piles driven into disturbed soil, have been shown to experience only minor to moderate corrosion. In either case the observed loss of material due to corrosion was not considered significant enough to impact the intended function of the piles, which is consistent with NUREG
-1557. The Groups 1, 3, 4, and 5 structures are monitored under the Structures Monitoring Program for cracks and distortion due to increased stress levels from settlement.
The staff's review of the applicant's Structures Monitoring Program is documented in SER Section 3.0.3.2.15. The LRA states that degradation of piles will manifest itself in settlement distortion or cracking of concrete, and accessible concrete examinations will detect cracks and distortion of the structures. The staff finds the use of the Structures Monitoring Program acceptable for managing the aging effects associated with these piles because the program Aging Management Review Results 3-348 inspects the concrete structures for indications of deterioration and distress, including cracking as defined in ACI 201.1R at a frequency not to exceed 5 years. The staff notes that for penetration seals as contained in the above AMR line items, the Structures Monitoring Program is a more appropriate AMP to monitor these items because they are not pressure boundary components; however, due to potential accessibility constraints associated with the penetration sleeves and seals being located in a groundwater/soil environment, the staff is unclear how the Structures Monitoring Program, which is primarily a visual-based program, will be used to address the structure/aging effect combinations during the period of extended operation. By a June 7, 2010 letter, the staff issued RAI 3.5.2.1-01 requesting that the applicant describe how the Structures Monitoring Program meets the GALL Report recommended programs and how the AMP will be used to manage the aging effects, including a discussion of preventive measure requirements.
In its Jul y 8, 2010 response, the applicant stated that the penetration sleeves were aligned to GALL Report item 3.3.1
-19 to show agreement between the LRA and the GALL Report with respect to the identified aging effects and mechanisms for the material and environment combination; the alignment was not intended to suggest consistency with the AMP recommended by the GALL Report and that the recommended GALL Report programs are not applicable for aging management of the penetration sleeves. The applicant also stated that the penetration sleeves are installed in concrete walls and the majority of the sleeve is located within the wall, while a small portion may protrude past the wall surface and into a soil environment and that most of the sleeve is protected on both the outer and inner surface by concrete, grout, or elastomer seal material. The applicant further stated that potential degradation of the small portion of the steel sleeve that protrudes past the exterior wall surface and is subject to the groundwater/soil environment will not impact the intended function given that most of the sleeve is protected on both the inner and outer surface and thus, degradation of this area of the sleeve is unlikely to penetrate to a wall depth sufficient to impact the intended function. The applicant stated that the Structures Monitoring Program includes inspections of the penetration seals and the associated sleeves on a 5
-year interval. These inspections will detect material degradation or indications of seal leakage prior to loss of intended function. The applicant also stated that for the buried conduit, the switchyard is the only structure that contains sections of inaccessible buried galvanized steel conduit within the scope of license renewal, extending from underground duct banks to manhole wall penetrations. The applicant further stated that periodic inspections of the penetrations and conduit ends will detect the presence of any water leakage, which would signify degradation of the conduit, prior to loss of intended function of the contained cable and in addition, the conduit will be inspected opportunistically when made accessible during maintenance activities The staff reviewed the applicant's response and notes that the penetration sleeves are structural components embedded in concrete and that the buried portion is not reasonably accessible for inspection. Visual inspections from the inside of the wall, on a 5
-year frequency, will be able to detect degradation prior to a loss of intended function. Based on its review, the staff finds the applicant's aging management approach acceptable because the Structures Monitoring Program includes appropriate inspections to detect degradation of the penetration sleeves prior to a loss of intended function and the conduit will be inspected by checking for the presence of water or opportunistically during maintenance activities. The staff notes that the SRP-LR does not typically allow aging management to occur via detection of a failure of a component, but given the inaccessibility of the conduit and the fact that short term exposure of intact cable to moisture will not result in immediate failure, the staff finds it to be an acceptable alternative. The staff's concern in RAI 3.5.2.1-01 is resolved
 
Aging Management Review Results 3-349 The staff finds the use of the Structures Monitoring Program for managing the aging effects associated with these penetration sleeves acceptable for the reasons as stated in the staff's evaluation of the applicant's response to RAI 3.5.2.1-01. 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 determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that 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).
3.3.2.2.9  Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced Corrosion and Fouling The staff reviewed LRA Section 3.3.2.2.9 against the criteria in SRP
-LR Section 3.3.2.2.9.
  (1) LRA Section 3.3.2.2.9, item 1 refers to Table 3.3.1, item 3.3.1
-20 and 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, and microbiologically
-influenced corrosion and fouling. The applicant addressed the further evaluation criteria of the SRP
-LR by stating that loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion and fouling in the steel piping, piping components, piping elements, and tanks exposed to fuel oil in the fuel oil system will be managed by the Fuel Oil Chemistry and One
-Time Inspection programs.
The staff reviewed LRA Section 3.3.2.2.9, item 1 against the criteria described in SRP-LR Section 3.3.2.2.9, item 1, which states that loss of material due to general, pitting, crevice, and microbiological ly-influenced corrosion and fouling could occur for steel piping, piping components, piping elements, and tanks exposed to fuel oil. The SRP-LR also states that the AMP relies on monitoring and control of fuel oil contamination to mitigate degradation. The SRP-LR further states that a one
-time inspection of selected components at susceptible locations is an acceptable method to determine whether an aging effect is not occurring or progressing very slowly such that the component's intended function will be maintained during the period of extended operation. The GALL Report, under item VII.H1-10, recommends managing the aging effect using the Fuel Oil Chemistry Program augmented by the One
-Time Inspection pProgram to verify the effectiveness of the fuel oil chemistry control.
The staff reviewed the applicant's Fuel Oil Chemistry and One
-Time Inspection programs and its evaluations are documented in SER Sections 3.0.3.2.8 and 3.0.3.1.11, respectively. The applicant stated that the One
-Time Inspection Program includes:  (1) determination of sample size based on an assessment of materials, environment, plausible aging effects and mechanisms, and operating experience; (2) identification of inspection locations based on the aging effect; (3) selection of the examination technique with acceptance criteria; and (4) evaluation of the results including the need for additional inspections or other corrective actions. The staff finds the credited programs acceptable to manage aging for these components because (1) the Fuel Oil Chemistry Program will assure that contaminates are maintained at acceptable levels in Aging Management Review Results 3-350 fuel oil and identify the actions required if the fuel oil contaminates exceed limits, and (2) the One-Time Inspection Program will include a one
-time inspection of selected components at appropriate locations (e.g., low or stagnant flow areas) to verify the effectiveness of the Fuel Oil Chemistry Program for managing the effects of aging due to the potential corrosion mechanisms.
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 those items that apply to LRA Section 3.3.2.2.9, item 1, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging 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).    (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, and microbiologically
-influenced corrosion and fouling 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 is not applicable because there are no steel heat exchanger components exposed to lubricating oil in the auxiliary systems.
The staff reviewed LRA Section 3.3.2.2.9.2 against the criteria in SRP
-LR Section 3.3.2.2.9, item 2, which states that loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion and fouling could occur for steel heat exchanger components 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 contaminant control should be verified 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 Lube Oil Chemistry Control 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 reviewed the UFSAR to verify that there are no steel heat exchanger components exposed to lubricating oil in the auxiliary systems.
Based on information in the UFSAR, the staff confirmed that the applicant's plant does not have steel heat exchanger components exposed to lubricating oil in the auxiliary systems. Therefore, the staff finds that this item is not applicable.
Based on a review of the programs identified above, the staff concludes that the applicant's programs meet SRP
-LR Section 3.3.2.2.9 criteria. For those line items that apply to LRA Section 3.3.2.2.9, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the Aging Management Review Results 3-351 intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.2.10 Loss of Material Due to Pitting and Crevice Corrosion The staff reviewed LRA Section 3.3.2.2.10 against the criteria in SRP
-LR Section 3.3.2.2.10.  (1) LRA Section 3.3.2.2.10.1, associated with LRA Table 3.3.1, item 3.3.1
-22, addresses pitting and crevice corrosion in steel with elastomer lining or stainless steel cladding piping, piping components, and piping elements exposed to treated water and treated borated water. The applicant stated that this line item is not applicable because the applicant's auxiliary systems do not contain steel piping with elastomer lining or steel piping with stainless steel cladding exposed to treated water. The staff reviewed LRA Sections 2.3.3 and 3.3, and the and confirmed that no steel with elastomer lining or stainless steel cladding piping, piping components, and piping elements exposed to treated water and treated borated water within scope are present in the auxiliary systems and, therefore, finds the applicant's determination acceptable.
  (2) LRA Section 3.3.2.2.10.2 referenced by LRA Table 3.3.1 item 3.3.1
-24 addresses stainless steel piping, piping components, piping elements and tanks exposed to treated water which are being managed for pitting and crevice corrosion by the Water Chemistry Program. The GALL Report recommends that the effectiveness of the chemistry control program be verified, and a one
-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion is not occurring. The applicant addressed the further evaluation criteria of the SRP
-LR by stating that it will implement the Water Chemistry and One Time Inspection Programs to manage the loss of material due to pitting and crevice corrosion for stainless steel piping, piping components, piping elements and tanks in the Chemical and Volume Control, Reactor Coolant and Containment Spray Systems. The staff notes that SRP
-LR references both 3.3.1-23 and 3.3.1
-24. The staff also notes that 3.3.1
-23 is not applicable to Salem units because they are PWRs and 3.3.1
-23 applies only to BWRs.
The staff reviewed LRA Section 3.3.2.2.10.2 against the criteria in SRP
-LR Section 3.3.2.2.10 Item 2, which states that loss of material due to pitting and crevice corrosion could occur for stainless steel and aluminum piping, piping components, piping elements, and for stainless steel and steel with stainless steel cladding heat exchanger components exposed to treated water. The SRP
-LR also states that the existing aging management program relies on monitoring and control of water chemistry to manage the aging effects of loss of material from pitting and crevice corrosion. Furthermore, the SRP-LR states that the GALL Report recommends a one
-time inspection of selected components at susceptible locations as an acceptable method to ensure that corrosion is not occurring and that the component's intended function will be maintained during the period of extended operation.
The staff's evaluation of the applicant's Water Chemistry and One
-Time Inspection programs is documented in SER Sections 3.0.3.1.2 and 3.0.3.1.11, respectively. The staff notes that the applicant stated that their primary and secondary water portions are consistent with the EPRI guidelines recommended by the GALL Report. The staff also notes that the applicant stated that its Water Chemistry Program includes periodic sampling of primary and secondary water for detrimental contaminants specified in EPRI Aging Management Review Results 3-352 water chemistry guidelines. The staff further notes that the applicant's One
-Time Inspection Program will use visual and volumetric inspection techniques performed per ASME Code standards to confirm the effectiveness of the Water Chemistry Program at mitigating the effects of aging. In its review of components associated with line item 3.3.1-24, 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 will mitigate loss of material due to pitting and crevice corrosion by managing containments ingress into the systems below the levels known to cause pitting and crevice corrosion. Furthermore, the One
-Time Inspection Program will verify the effectiveness of the Water Chemistry Program in low flow areas, such that the component's intended function will be maintained during the period of extended operation.
Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.10.2 criteria. For those line items that apply to LRA Section 3.3.2.2.10, item 2, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
  (3) LRA Section 3.3.2.2.10.3 refers to LRA Table 3.3.1, item 3.3.1
-25 and addresses copper alloy HVAC piping, piping components, and piping elements exposed to condensation (external), which are being managed for loss of material due to pitting and crevice corrosion by the Periodic Inspection Program. The applicant addressed the further evaluation criteria of the SRP
-LR by stating that the Periodic Inspection Program will be implemented to manage loss of material due to pitting and crevice corrosion of the copper alloy HVAC piping, piping components, and piping elements exposed to wetted air or gas in the auxiliary building ventilation, chilled water, control area ventilation system, and the heating water and heating steam system. The applicant stated that the wetted air or gas environment assumed for these components includes the potential for wetting due to condensation. The applicant also stated that the Periodic Inspection Program includes visual inspections to assure that existing environmental conditions are not causing material degradation that could result in a loss of component inte nded functions.
The staff reviewed LRA Section 3.3.2.2.10.3 against the criteria in SRP
-LR Section 3.3.2.2.10, item 3, which 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. The SRP
-LR also states that the reviewer reviews the applicant's proposed program on a case
-by-case basis to ensure that an adequate program will be in place for the management of these aging effects.
The staff's evaluation of the applicant's Periodic Inspection Program is documented in SER Section 3.0.3.3.2. The staff notes that the applicant is using the Periodic Inspection Program to manage loss of material due to pitting and crevice corrosion for copper allo y HVAC piping, piping components, and piping elements exposed to condensation by conducting visual inspection of copper alloy HVAC piping, piping components, and piping elements exposed to condensation to detect pitting and crevice corrosion. In its review of components associated with item 3.3.1
-25, the staff finds the applicant's proposal to manage aging using the Periodic Inspection Program acceptable because it satisfies the acceptance criteria in SRP
-LR Section 3.3.2.2.10, item 3 by requiring visual Aging Management Review Results 3-353 inspection techniques which will be able to detect loss of material due to pitting and crevice corrosion.
Based on the program identified, the staff concludes that the applicant's program meets SRP-LR Section 3.3.2.2.10, item 3 criteria. For those line items that apply to LRA Section 3.3.2.2.10.3, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
  (4) LRA Section 3.3.2.2.10.4, referenced by LRA 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 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 copper alloy heat exchanger components exposed to lubricating oil in the component cooling system.
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 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 verified 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 lube oil chemistry 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 evaluation of the applicant's Lubricating Oil Analysis and One
-Time Inspection programs is documented in SER Sections 3.0.3.2.12 and 3.0.3.1.11, 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 (1) the Lubricating Oil Analysis Program was determined to be consistent with the GALL Report, and (2) 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 SRP
-LR Section 3.3.2.2.10, item 4 and, therefore, the applicant's AMR is consistent with the GALL Report items VII.C1
-8, VII.C2-5, VII.E1-12, VII.G-11, and VII.H2-10. Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.10, item 4 criteria. For the line items that apply to LRA Section 3.3.2.2.10.4, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be Aging Management Review Results 3-354 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 3.3.2.2.10.5 refers to LRA Table 3.3.1, item 3.3.1
-27 and addresses HVAC aluminum piping, piping components, and piping elements and stainless steel ductin g and components exposed to condensation, which are being managed for loss of material due to pitting and crevice corrosion by the Periodic Inspection Program.
The applicant addressed the further evaluation criteria of the SRP
-LR by stating that the Periodic Inspection Program will be implemented to manage loss of material due to pitting and crevice corrosion of the stainless steel and aluminum HVAC ducting and ducting components, piping, piping components, and piping elements exposed to wetted air in the auxiliary building ventilation, chemical and volume control, component cooling, compressed air, containment spray, containment ventilation, control area ventilation, EDGs and auxiliaries, fuel handling ventilation, radioactive drain, reactor coolant, residual heat removal, safety injection, service water, service water ventilation, and switchgear and penetration area ventilation systems. The applicant stated that the wetted air or gas environment assumed for these components includes the potential for wetting due to condensation. The applicant also stated that the Periodic Inspection Program includes visual inspections to assure that existing environmental conditions are not causing material degradation that could result in a loss of component intended functions. By a June 25, 2010 letter, the staff issued RAI 3.3.2.2.10.6
-01 related to the applicant's Fire Protection Program. The RAI requested that the applicant provide justification for how the Fire Protection Program will adequately manage the aging effect of loss of material due to pitting and crevice corrosion. In its July 21, 2010 response, the applicant stated that aluminum piping, piping components, and piping elements in the fire protection system were incorrectly identified as being in a wetted environment. As a result of the newly applied environment, the applicant has determined that the aging effect no longer applies. The staff's evaluation of the RAI response is documented in SER Section 3.3.2.2.10.6.
The staff reviewed LRA Section 3.3.2.2.10.5 against the criteria in SRP
-LR Section 3.3.2.2.10, item 5, which 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 the reviewer conducts an evaluation of a plant
-specific AMP to ensure that these aging effects are adequately managed and that acceptance criteria are described in Branch Technical Position RLSB
-1. The staff's evaluation of the applicant's Periodic Inspection Program is documented in SER Section 3.0.3.3.2. The staff notes that the applicant is using the Periodic Inspection Program to manage loss of material due to pitting and crevice corrosion for HVAC aluminum piping, piping components, and piping elements and stainless steel ducting and components exposed to condensation by conducting visual inspections to detect pitting and crevice corrosion. In its review of components associated with item 3.3.1-27, the staff finds the applicant's proposal to manage aging using the Periodic Inspection Program acceptable because it satisfies the acceptance criteria in SRP
-LR Section 3.3.2.2.10, item 5 by requiring visual inspection techniques in the Periodic Inspection Program which will be able to detect loss of material due to pitting and crevice corrosion.
 
Aging Management Review Results 3-355  Based on the program identified, the staff concludes that the applicant's program meets SRP-LR Section 3.3.2.2.10, item 5 criteria. For those line items that apply to LRA Section 3.3.2.2.10.5, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3)
  (6) LRA Section 3.3.2.2.10, item 6 is associated with Table 3.3-1, item 3.3.1
-28 and addresses copper alloy fire protection 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. The applicant addressed the further evaluation criteria of the SRP
-LR by stating that these components are managed for loss of material due to pitting and crevice corrosion by the Periodic Inspection, Compressed Air Monitoring, Fire Protection, or Fire Water System programs.
The staff reviewed LRA Section 3.3.2.2.10, item 6, against the criteria in SRP
-LR Section 3.3.2.2.10, item 6, which states that loss of material due to pitting and crevice corrosion could occur for copper alloy fire protection system 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.
The staff reviewed the applicant's Fire Protection Program and its evaluation is documented in SER Section 3.0.3.2.5. In its review of components associated with item 3.3.1-28, the staff notes that the applicant credited the Fire Protection Program to manage loss of material for copper alloy spray nozzles, piping and components, and valve bodies exposed to wetted air or gas in LRA Table 3.3.2-12. The staff also notes that the Fire Protection Program includes visual inspections of fire barriers and the external surfaces of the halon and CO 2 systems and performance testing of the diesel driven fire pump fuel supply lines. The staff further notes that the description of the Fire Protection Program does not include criteria for inspections of the internal surfaces of components which could detect loss of material for the copper alloy spray nozzles, piping and components, and valve bodies exposed to wetted air or gas listed in LRA Table 3.3.2-12. By a June 25, 2010 letter, the staff issued RAI 3.3.2.2.10.6
-1 requesting that the applicant justify how the Fire Protection Program will adequately manage loss of material for these copper alloy components.
In its July 21, 2010 response, the applicant stated that the halon and CO 2 dispersion systems contain copper alloy piping, fittings, and valves between the isolation valves and open spray nozzles that are exposed to the same environment as the external surfaces. The applicant also stated that the environment was conservatively listed as wetted air or gas, but that these components are not subject to internal condensation. The applicant further stated that the CO 2 dispersion system aluminum odorizer is also downstream of the isolation valves and not subject to internal condensation. As a result, the applicant revised the AMR line items for the aluminum odorizer and copper alloy piping, fittings, and valve bodies that credited the Fire Protection Program to change the environment to indoor air, change the aging effects to none, and change the AMP to none. The AMR line item for the aluminum odorizer was revised to reference item 3.2.1-50 and cite generic note A. The AMR line item for the copper alloy piping and fittings was revised to reference item 3.4.1
-41 and cite generic note A. The AMR line Aging Management Review Results 3-356 items for valve bodies were revised to reference item 3.2.1
-53 and cite generic note A. The staff notes that the new line items referenced correspond with appropriate GALL Report items that recommend that there are no AERMs for this material and environment combination. The staff finds the applicant's response to RAI 3.3.2.2.10.6
-1 acceptable because (1) the internal environment for components downstream from the isolation valves in the halon and CO 2 fire suppression systems should be the same as the external environment; (2) the external environment for the halon and CO 2 fire suppression systems is indoor air, which is not expected to contribute to corrosion of these components; (3) the applicant has chosen appropriate alternate line items that recommend no aging effects for these components when exposed to an indoor air environment; and (4) the applicant has made the corresponding revisions to the LRA. During the applicant's review of items in Table 3.3.2-12, the applicant stated that it incorrectly included AMR results for copper alloy spray nozzles in its foam fire suppression system for the gas turbine facility, which is not within the scope of license renewal. In its response to RAI 3.3.2.2.10.6
-1, the applicant revised Table 3.3.2-12 to remove the two AMR results for the copper alloy foam system spray nozzles. The staff finds the deletion of the foam system spray nozzles acceptable because the foam system associated with the gas turbine facility is not within the scope of license renewal and, therefore, the components do not require an aging management program. The staff's concern described in RAI 3.3.2.2.10.6
-1 is resolved.
The staff reviewed the applicant's Fire Water System Program and its evaluation is documented in SER Section 3.0.3.2.6. In its review of components associated with item 3.3.1-28, the staff notes that the applicant credited the Fire Water System Program to manage loss of material for sprinkler heads and valve bodies in LRA Table 3.3.2-10. The staff also notes that the Fire Water System Program manages aging effects for the water-based fire protection system and associated components through the use of periodic inspections, monitoring, and performance testing and that the applicant stated an enhancement to the program to replace or perform 50
-year sprinkler head inspections and testing using the guidance of NFPA
-25, "Standard for the Inspection, Testing and Maintenance of Water-Based Fire Protection Systems" (2002 Edition), Section 5-3.1.1. The applicant stated that these inspections will be performed by the 50-year in service date and every 10 years thereafter. The staff finds the applicant's Fire Water System Program acceptable to manage loss of material due to pitting and crevice corrosion for these components because (1) the copper alloy sprinkler heads will be replaced or inspections will be performed consistent with GALL AMP XI.M27 and NFPA-25, and (2) the copper alloy valve bodies will be inspected and be part of the monitoring program consistent with GALL AMP XI.M27.
The staff reviewed the applicant's Periodic Inspection Program and its evaluation is documented in SER Section 3.0.3.3.2. In its review of components associated with item 3.3.1-28, the staff notes that the applicant credited the Periodic Inspection Program to manage loss of material for copper alloy heat exchanger components in LRA Table 3.3.2-3 and copper alloy valve bodies in LRA Table 3.3.2-11. The staff also notes that the Periodic Inspection Program includes provisions for visual inspection of stainless steel, aluminum, copper alloy, and elastomer components and ultrasonic wall thickness measurements to detect loss of material. The staff finds the applicant's Periodic Inspection Program acceptable to manage loss of material due to pitting and crevice corrosion for copper alloy heat exchanger components and valve bodies because (1) visual inspections will be performed on component surfaces that are either normally accessible or made accessible during periodic component disassembly, and (2) wall Aging Management Review Results 3-357 thickness measurements will be performed on a representative sample of piping locations selected from systems within the scope of this program that are not normally opened for maintenance.
The staff reviewed the applicant's Compressed Air Monitoring Program and its evaluation is documented in SER Section 3.0.3.1.10. In its review of components associated with item 3.3.1
-28, the staff notes that the applicant credited the Compressed Air Monitoring Program to manage loss of material for copper alloy valve bodies in LRA Table 3.3.2-6. The staff also notes that the Compressed Air Monitoring Program includes leakage testing and inspections of air system components and air quality checks at various locations in the system to ensure that dew point, particulates, lubricant content, and contaminants are kept within the limits specified in ANSI/ISA 7.0.01
-1996. The staff finds the applicant's Compressed Air Monitoring Program acceptable to manage loss of material for these components because air quality checks and periodic inspections will mitigate and detect corrosion prior to loss of intended function.
Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2.10.6 criteria. For those line items that apply to LRA Section 3.3.2.2.10.6, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
  (7) LRA Section 3.3.2.2.10.7 refers to Table 3.3.1, item 3.3.1
-29 and addresses loss of material due to pitting and crevice corrosion in stainless steel piping, piping components, and piping elements exposed to soil. The applicant stated that this item is not applicable because there are no stainless steel piping, piping components, and piping elements buried in soil in the auxiliary systems. The staff reviewed the LRA AMR items and information in the UFSAR associated with Table 3.3.1, items 3.3.1
-29 and confirms that there are no stainless steel piping, piping components, and piping elements exposed to soil in the auxiliary systems and subjected to loss of material due to pitting and crevice corrosion. Therefore, the staff finds the applicant's determination that LRA Table 3.3.1, item 3.3.1
-29 is not applicable acceptable.  (8) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion, stating that this aging effect is not applicable to Salem, which is a PWR.
SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice corrosion may occur in stainless steel piping, piping components, and piping elements of the BWR standby liquid control system exposed to sodium pentaborate solution.
Salem units are PWRs and do not have a standby liquid control system. The staff agree s that this item is not applicable to Salem.
Based on a review of the programs identified above, the staff concludes that the applicant's programs meet SRP
-LR Section 3.3.2.2.10 criteria. For those line items that apply to LRA Section 3.3.2.2.10, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.2.11 Loss of Material Due to Pitting, Crevice, and Galvanic Corrosion
 
Aging Management Review Results 3-358 The staff reviewed LRA Section 3.3.2.2.11 against the criteria in SRP
-LR Section 3.3.2.2.11.
LRA Section 3.3.2.2.11 addresses loss of material due to pitting, crevice, and galvanic corrosion, stating that this aging effect is not applicable to Salem units, which are PWRs.
SRP-LR Section 3.3.2.2.11 states that loss of material due to pitting, crevice, and galvanic corrosion may occur in copper alloy piping, piping components, and piping elements exposed to treated water.
This item pertains to loss of material in copper alloy auxiliary system components exposed to a BWR treated water environment. Salem units are PWRs. The staff agrees that this item is not applicable to Salem.
Based on the above, the staff concludes that SRP
-LR Section 3.3.2.2.11 criteria do not apply.
3.3.2.2.12 Loss of Material Due to Pitting, Crevice, and Microbiologically
-Influenced Corrosion The staff reviewed LRA Section 3.3.2.2.12 against the criteria in SRP
-LR Section 3.3.2.2.12.
  (1) LRA Section 3.3.2.2.12, item 1, refers to 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 microbiologically
-influenced corrosion. The applicant addressed the further evaluation criteria of SRP
-LR by stating that loss of material due to pitting, crevice, and microbiologically
-influenced corrosion in the stainless steel, aluminum, and copper alloy piping, piping components, and piping elements exposed to fuel oil in the fuel oil system will be managed by the Fuel Oil Chemistry and One
-Time Inspection programs.
The staff reviewed LRA Section 3.3.2.2.12, item 1, against the criteria described in SRP-LR Section 3.3.2.2.12, item 1, which states that loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion and fouling could occur for steel piping, piping components, piping elements, and tanks exposed to fuel oil. The SRP-LR also states that the AMP relies on monitoring and control of fuel oil contamination to mitigate degradation. The SRP
-LR further states that a one
-time inspection of selected components at susceptible locations is an acceptable method to determine whether an aging effect is not occurring or progressing very slowly such that the component's intended function will be maintained during the period of extended operation. The GALL Report, under items VII.H1-1, VII.H1-3, and VII.H1-6, recommends managing the aging effect using the Fuel Oil Chemistry Program augmented by the One
-Time Inspection Program to verify the effectiveness of the fuel oil chemistry control.
The staff reviewed the applicant's Fuel Oil Chemistry and the One
-Time Inspection programs, which are evaluated in SER Sections 3.0.3.2.8 and 3.0.3.1.11, respectively. The applicant stated that the One
-Time Inspection Program includes (1) determination of sample size based on an assessment of materials, environment, plausible aging effects and mechanisms, and operating experience; (2) identification of inspection locations based on the aging effect; (3) selection of the examination technique with acceptance criteria; and (4) evaluation of the results including the need for additional inspections or other corrective actions. The staff finds the credited programs acceptable to manage aging for these components because (1) the Fuel Oil Chemistry Program will assure that contaminates are maintained at acceptable levels in fuel oil and identify the actions Aging Management Review Results 3-359 required if the fuel oil contaminates exceed limits, and (2) the One
-Time Inspection Program will include a one
-time inspection of selected components at appropriate locations (e.g., low or stagnant flow areas) to verify the effectiveness of the Fuel Oil Chemistry Program for managing the effects of aging due to the potential corrosion mechanisms.
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, item 1, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that their intended function 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 by LRA 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 managed for loss of material due to pitting, crevice, and microbiologically
-influenced 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, piping components, piping elements, and heat exchanger components exposed to lubricating oil for the component cooling, EDGs and auxiliaries, reactor coolant, and service water 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 microbiologically
-influenced corrosion 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 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 verified 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 evaluation of the applicant's Lubricating Oil Analysis and One
-Time Inspection programs is documented in SER Sections 3.0.3.2.12 and 3.0.3.1.11, 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 (1) the Lubricating Oil Analysis Program was determined to be consistent with the GALL Report, and (2) 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 Aging Management Review Results 3-360 and, therefore, the applicant's AMR is consistent with GALL Report items VII.C1
-14, VII.C2-12, VII.E1
-15, VII.E4
-12, VII.G-18, and VII.H2
-17. Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.3.2.2, item 12 criteria. For the line items that apply to LRA Section 3.3.2.2.12.1 and 3.3.2.2.12.2, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
Based on a review of the programs identified above, the staff concludes that the applicant's programs meet SRP
-LR Section 3.3.2.2.12 criteria. For those line items that apply to LRA Section 3.3.2.2.12, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.2.13 Loss of Material Due to Wear LRA Section 3.3.2.2.13 refers to Table 3.3.1, item 3.3.1
-34 and addresses elastomer components that are subject to wear in the applicant's auxiliary systems. The applicant stated that elastomer components determined to be subject to wear, based on plant operating experience, are periodically replaced and are not subject to an AMR. The applicant further stated that elastomer components that are not periodically replaced are evaluated for hardening and loss of strength due to elastomer degradation in LRA Table 3.3.1, item 3.3.1
-11 and are included in the Periodic Inspection Program.
The staff reviewed LRA Section 3.3.2.2.13 against the criteria in SRP
-LR Section 3.3.2.2.13, which states that loss of material due to wear can occur in elastomer seals and components exposed to uncontrolled indoor air. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that the aging effect is adequately managed.
The staff noted that the applicant invokes periodic replacement of elastomer components subject to wear as its basis for not subjecting the components to an AMR. The staff further noted that this basis is consistent with requirements of 10 CFR 54.21(a)(ii). However, the staff did not find sufficient information in the LRA to confirm that the frequency of the applicant's component replacement is adequate. By a July 23, 2010 letter, the staff issued RAI 3.3.2.2.13
-01 requesting that the applicant:  (1) identify what systems contain in
-scope elastomer components that are subject wear and periodically replaced, and (2) provide the basis for determining the replacement frequency of those components.
In its August 10, 2010 response dated, the applicant stated that the only in
-scope elastomer components that experience wear and are subject to periodic replacement are fire hoses. The applicant also stated that fire hoses are subject to relative motion when installed on hose reels or hose racks, or when deployed for use or testing. The applicant further stated that as per LRA Section 2.1.6.4, fire hoses are considered to be a consumable item whose replacement frequency is based on NFPA testing and inspection standards that are implemented by controlled station procedures.
 
Aging Management Review Results 3-361 The staff notes that although the replacement frequency for the fire hoses is based on testing and inspection, this testing and inspection is controlled by plant procedures based on NFPA standards and use of NFPA standards is consistent both with standard industry practice and with recommendations in GALL AMP XI.M27, "Fire Water System."  The staff finds the applicant's response acceptable because the within scope fire hoses that are subject to wear are appropriately evaluated as not being long
-lived passive items and thus are screened out from aging management. The staff's concern described in RAI 3.3.2.2.13
-01 is resolved.
Based upon the applicant's periodic replacement of elastomer components subject to wear, the staff finds that an AMR of these components is not required and finds it acceptable for the applicant to designate AMR results in Table 3.3.1, item 3.3.1
-34 as not applicable.
3.3.2.2.14 Loss of Material Due to Cladding Breach LRA Section 3.3.2.2.14 is referenced by Table 3.3.1, item 3.3.1-35 and addresses steel charging pump casings with stainless steel cladding exposed to treated borated water, which are being managed for loss of material due to cladding breach by the One
-Time Inspection Program for Unit 2. The applicant addressed the further evaluation criteria of the SRP
-LR by stating that this item is only applicable to Unit 2 because the Unit 1 charging pumps have been changed to all stainless steel pump casings following the inspections in 1997 and 1998. The applicant further stated that the Unit 2 pumps are also included with item 3.3.1-91, which is being managed by the Water Chemistry Program and that the effectiveness of the Water Chemistry Program will be verified by the One
-Time Inspection Program.
The staff reviewed LRA Section 3.3.2.2.14 against the criteria described in SRP
-LR Section 3.3.2.2.14, which states that loss of material due to cladding breach could occur for steel charging pump casings with stainless steel cladding exposed to treated borated water. The SRP-LR also states that the GALL Report recommends further evaluation of a plant-specific AMP to ensure that the aging effect is adequately managed and that the acceptance criteria are described in Branch Technical Position RSLB
-1. The staff's evaluation of the applicant's One
-Time Inspection Program is documented in SER Section 3.0.3.1.11. The staff notes that the applicant's One
-Time Inspection Program includes determination of sample size based on an assessment of materials, environment, plausible aging effects and mechanisms, and operating experience, and the identification of inspection locations is based on the aging effect. In its review of components associated with item 3.3.1-35, the staff finds the applicant's proposal to manage aging using the above program acceptable because the One
-Time Inspection Program will verify that unacceptable degradation is not occurring.
Based on the program identified, the staff concludes that the applicant's program meets SRP-LR Section 3.3.2.2.14 criteria. For those items that apply to LRA Section 3.3.2.2.14, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging 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).
3.3.2.2.15 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.
 
Aging Management Review Results 3-362 3.3.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report In LRA Tables 3.3.2-1 through 3.3.2
-26, 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 3.3.2-1 through 3.3.2
-26, the applicant indicated, via generic notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report. The applicant provided further information concerning how the aging effects will be managed. Specifically, note F indicates that the material for the AMR line item component is not evaluated in the GALL Report. Note G indicates that the environment for the AMR line item component and material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR line item component, material, and environment combination is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the line item component, material, and environment combination is not applicable. Not e J indicates that neither the component nor the material and environment combination for the line item is evaluated in the GALL Report.
LRA Table 3.3.2-14 was revised as a result of the response to RAI B.2.1.9-01, dated July 8, 2010. The revision added AMR items in these tables to reference the applicant's Bolting Integrity Program to manage the aging for bolting AMR items. Existing bolting AMR items which reference other AMPs are used in conjunction with the added bolting AMR items to properly manage aging for bolting components. The staff's evaluation of the applicant's Bolting Integrity Program is documented in SER Section 3.0.3.2.2. The staff notes that the Bolting Integrity Program is supplemented by other AMPs, including but not limited to the Structures Monitoring, Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems, External Surfaces Monitoring, and Buried Piping Inspection programs. These other AMPs supplement the Bolting Integrity Program by implementing the requirements of the Bolting Integrity Program for pressure
-retaining bolted joints, component support bolting, and structural bolting within the scope of license renewal. The applicant's action accurately adds the related line items to reference the Bolting Integrity Program; however the technical evaluations documented in the SER do not change since the management of the aging effect will still be implemented by the AMP identified in conjunction with the Bolting Integrity Program.
For component type, material, and environment combinations not evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine whether the applicant had demonstrated that the aging effects will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation. The staff's evaluation is discussed in the following sections.
3.3.2.3.1  Auxiliary Systems
- Auxiliary Building Ventilation System
- Summary of 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 building ventilation system component groups.
In LRA Tables 3.3.2-1, 3.3.2-3, 3.3.2-6, 3.3.2-8, 3.3.2-15, 3.3.2-19, 3.3.2-22, 3.3.2-26, and 3.1.2-1, the applicant stated that for glass filter housings, sight glasses, flow elements, and tanks (sampling vessels and accumulators) exposed to air with borated water leakage, wetted air or gas, and closed
-cycle cooling water, there is no aging effect and no AMP is proposed.
Aging Management Review Results 3-363 The AMR line items cite generic note G, indicating that the environment is not in the GALL Report for these components and material.
The staff reviewed all AMR result line items in the GALL Report where the material is glass and confirms that for this environment, there are no entries in the GALL Report for this component and material.
The staff finds the applicant's proposal acceptable because, as supported by various GALL Report line items such as EP
-15, EP-29, and EP
-30, there are no known aging effects for glass exposed to any water environment of nuclear power plants.
In LRA Tables 3.3.2-1, 3.3.2-7, 3.3.2-15, and 3.3.2
-26, the applicant stated that elastomer door seals and flexible connections exposed to air with treated borated water leakage has no AERM and that for this component, material, and environment combination, no AMP is needed. The AMR line items cite generic note G, indicating that the environment is not in the GALL Report for this component and material.
The staff reviewed all AMR results in the GALL Report where the component type is elastomer door seals or flexible connections and confirms that there are no entries for this component and material combination where the environment is wetted air or gas, or similar.
The staff notesthat the LRA does not provide sufficient information to evaluate the effect of the air with borated water leakage and to wetted air or gas environments for components in this system because the LRA does not explain how these components are exposed to these environments. By letter dated June 11, 2010, the staff issued RAI 3.3.2-02 requesting that the applicant provide sufficient information for the staff to evaluate the effect of these environments for components in these systems.
In its response dated July 8, 2010, the applicant stated that all components in the auxiliary building (including the inner penetration area), containment structure, and fuel handling building, two external environments are applied:  indoor air and air with borated water leakage. The applicant also stated that probability of an elastomer being exposed to borated water in these locations is extremely small, but the environment was included for completeness. The applicant further stated that ventilation components are assigned an environment of wetted air or gas unless the air is processed through filters or driers to remove moisture and contaminants.
The staff finds the applicant's response acceptable because it clarified the exposure mechanism and potential, allowing the staff to evaluate individual AMR line items. The staff's concern described in RAI 3.3.2-02 is resolved.
The staff noted a potential discrepancy between the applicant's AMR results for elastomer door seals and flexible connections exposed to wetted air or gas (internal) and the results for elastomer door seals and flexible connections exposed to air with treated borated water leakage. By letter dated June 11, 2010, the staff issued RAI 3.3.2-01 requesting that the applicant:  (1) provide a basis for its statement that there is no aging effect for elastomer door seals and flexible connections exposed to air with borated water leakage, and (2) explain why elastomer door seals and flexible connections exposed to wetted air or gas would exhibit an aging effect and similar components exposed to air with treated borated water leakage would not.
Aging Management Review Results 3-364 In its response dated July 8, 2010, the applicant stated that two external environments are applied to all components in the auxiliary building (including the inner penetration area), containment structure, and fuel handling building: indoor air and air with borated water leakage. The air with borated water leakage is included specifically to cover metallic component types whose external surfaces are susceptible to boric acid wastage. The applicant also stated that for elastomeric components located in these areas, the AMR line items where elastomers are exposed to air with borated water leakage, the intent was to state that there are no additional AERMs than for the same materials in the AMR line items exposed to an indoor air environment.
The staff finds the applicant's response and proposal that there are no additional AERMs and that for this component, material, and environment combination, no additional AMP is needed acceptable because the aging effects of hardening and loss of strength due to elastomer degradation as a result of being exposed to either indoor air or air with borated water leakage environment will be effectively managed by the Periodic Inspection Program, which includes visual inspections and physical manipulations to detect degradation. The staff's concern described in RAI 3.3.2-01 is resolved.
In LRA Tables 3.3.2-1, 3.3.2-7, 3.3.2-8, 3.3.2-15, and 3.3.2
-26, the applicant stated that elastomer door seals and flexible connections exposed to wetted air or gas (internal) has an aging effect of hardening and loss of strength due to elastomer degradation that will be managed by the Periodic Inspection Program. The AMR line items cited generic note G, indicating that the environment is not in the GALL Report for this component and material.
The staff reviewed all AMR results in the GALL Report where the component type is elastomer door seals or flexible connections and confirmed that there are no entries for this component and material combination where the environment is wetted air or gas, or similar. This review confirms that the applicant's use of generic note G is acceptable.
The staff reviewed the applicant's Periodic Inspection Program and its evaluation is documented in SER Section 3.0.3.3.3.2. In its review of the Periodic Inspection Program, the staff noted that it is a plant
-specific program that proposes to detect the aging of elastomer door seals and flexible connections through the use of visual inspections and physical manipulations. The staff finds the applicant's proposal to manage aging of elastomer door seals and flexible connections exposed to wetted air or gas (internal) using the Periodic Inspection Program acceptable because (1) the program performs visual inspections and physical manipulations that are capable of detecting hardening and loss of strength in elastomer components; and (2) the program initiates corrective actions, implemented through the applicant's corrective action program, if indications of age
-related degradation are found.
In LRA Table 3.3.2-1, the applicant stated that polymer piping and fittings exposed to air
- indoor (external), air with borated water leakage (external), or wetted air or gas (internal) have no AERM and that for this component, material, and environment combination, no AMP is needed. The AMR line items cite generic note F, indicating that the material is not in the GALL Report for this component.
The staff reviewed all material entries in the GALL Report and confirmed that polymer material is not included in the GALL Report. This review confirms that the applicant's use of generic note F is acceptable.
 
Aging Management Review Results 3-365 For these AMR results, the applicant also cited plant
-specific Note 5, stating that polymer (plexiglass) material located indoors and subject to an indoor air, wetted air or gas, or air with borated water leakage is not subject to significant aging effects. The applicant further stated that polymer materials do not experience aging effects unless exposed to temperatures, radiation, or chemicals capable of attacking the specific polymer chemical composition and that polymer materials selected for compatibility with the environment during the design will not experience significant degradation.
Based on its review of technical literature (including, Roff, W.J., Fibres, Plastics, and Rubbers: A Handbook of Common Polymers) and current industry research and operating experience related to plexiglass and related polymer piping and piping components, the staff determines that, in the absence of specific environmental stressors such as ultraviolet light, high radiation, or ozone concentrations, piping components made of these materials do not exhibit aging effects of concern during the period of extended operation.
The staff determines that for plexiglass and related polymer piping and piping components in a plant indoor air, air with boron leakage, or wetted environment, there are no aging effects that cause degradation of the components during the period of extended operation. On the basis that the subject components have no aging effects that cause degradation during the period of extended operation, the staff finds the applicant's AMR results for these components, indicating that there is no AERM and no AMP is needed, to be acceptable.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.3.2  Auxiliary Systems
- Chemical and Volume Control System
- Summary of 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 chemical and volume control system component groups.
In LRA Tables 3.3.2-2 and 3.4.
2-1, the applicant stated that stainless steel tanks exposed externally to soil are being managed for loss of material due to pitting, crevice, and microbiologically
-influenced corrosion by the Aboveground Non
-Steel Tanks Program. The AMR line items cite generic note G. The staff reviewed the applicant's Aboveground Non
-Steel Tanks Program and its evaluation is documented in SER Section 3.0.3.3.3. The staff finds the applicant's program acceptable to manage aging for these components because it includes visual inspections of the accessible outer surfaces of the tank, down to the concrete foundation, and thickness measurements of the tank bottom from inside of the tank to determine if there is any loss of material occurring where the exterior of the tank bottom is in contact with the soil.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
Aging Management Review Results 3-366 3.3.2.3.3  Auxiliary Systems
- Chilled Water System
- Summary of 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 chilled water system component groups.
In LRA Tables 3.3.2-3 and 3.3.2
-23, the applicant stated that copper alloy heat exchanger components exposed to wetted air and gas are being managed for reduction of heat transfer due to fouling by the Periodic Inspection Program. The AMR line items cite generic note G, indicating that the environment is not in the GALL Report for this component and material.
The staff reviewed all AMR line items in the GALL Report where the material is copper alloy and the aging effect is reduction of heat transfer and confirms that for this environment, there are no entries in the GALL Report for this component and material.
The staff's evaluation of the applicant's Periodic Inspection Program is documented in SER Section 3.0.3.3.2. The staff finds the monitoring program acceptable because it uses visual inspections which are appropriate to determine whether there is any loss of component function caused by reduction of heat transfer due to fouling. The visual inspections are consistent with the GALL Report and thus, the monitoring program will adequately manage the aging effect. On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.3.4  Auxiliary Systems
- Circulating Water System
- Summary of 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 circulating water system component groups.
In LRA Tables 3.3.2-4, 3.3.2-6, 3.3.2-10, 3.3.2-12, 3.3.2-18, and 3.3
.2-23 the applicant stated that carbon and low
-alloy steel bolting exposed to groundwater and soil is being managed for loss of preload due to thermal effects, gasket creep, and self
-loosening and loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion by the Bolting Integrity Program. The applicant also stated that it plans to conduct inspections in accordance with the frequency outlined in the Buried Piping Inspection Program. The staff reviewed the applicant's Bolting Integrity and Buried Piping Inspection programs and its evaluations are documented in SER Sections 3.0.3.2.2 and 3.0.3.2.10, respectively. The staff noted that the Bolting Integrity Program manages loss of material and loss of preload by performing visual inspections. The staff also noted that the Buried Piping Inspection Program inspection frequency is based upon the preventive measures established in the program, which include maintaining external coatings and wrappings. It is unclear to the staff if external coatings and wrappings are used on the carbon and low
-alloy steel bolting. By letter dated May 24, 2010, the staff issued RAI 3.3.2.3.4-1 requesting that the applicant indicate if coatings are used on this bolting and how those coatings are maintained. Secondly, the staff asked the applicant if coatings are not used, why is the frequency associated with the Buried Piping Aging Management Review Results 3-367 Inspection Program an acceptable level of monitoring when that program expects coatings to be used as a preventive measure.
In its response dated June 14, 2010, the applicant stated that station documentation and site interviews indicate that buried bolting was initially coated, but that buried carbon steel bolts in the fire protection system have been observed without coatings and that it does not take credit for coatings to prevent loss of intended function. The applicant also stated that buried bolting in the service water system is designated as Class 3 and is inspected in accordance with ASME Code Section XI IWD-2500 and IW D-5000, 1998 Edition with 2000 Addenda, which allows use of a flow test to confirm no significant leakage in lieu of visual inspections. The applicant further stated that non
-ASME buried bolts will be opportunistically inspected in accordance with the Buried Piping Inspection Program. The staff notes that ASME Code Section XI, SubSection IWA-5244, "Buried Components," indicates that for buried components where a VT-2 visual examination cannot be performed, the examination requirement is satisfied by conducting a pressure loss test or a flow test. The staff finds the applicant's response to RAI 3.3.2.3.4-1 and its proposal to manage aging for bolting exposed to soil using the Bolting Integrity and Buried Piping Inspection programs acceptable because the buried bolts will be inspected using either system flow tests or opportunistic inspections, which is consistent with the GALL Report recommendations that periodic inspections be conducted. The staff's concern described in RAI 3.3.2.3.4-1 is resolved
. In LRA Tables 3.3.2-4 and 3.3.2
-23, for component type piping and fittings, the applicant proposed to assign reinforced concrete to the Open
-Cycle Cooling Water System Program to manage the aging effects of cracking, loss of bond, loss of material (spalling, scaling)/corrosion of embedded steel, increase in porosity and permeability, and aggressive chemical attack in a raw water (internal) groundwater/soil environment. This item references generic note J or note F (depending on the table). The applicant stated that these components have the intended function of pressure boundary and are examined using the Open
-Cycle Cooling Water System Program. The staff's review of the applicant's Open
-Cycle Cooling Water System Program is documented in SER Section 3.0.3.1.9.
The staff notes that the applicant's Open
-Cycle Cooling Water System Program includes activities to manage internal degradation of piping, including cracking, loss of material, and increase in porosity and permeability. The staff also notes that the concrete piping within scope of this program has a polymer coating applied to the interior surface of the pipe and the interior of each piping header is visually inspected every other refueling outage for signs of coating and concrete degradation. Visual inspections of the piping header will detect indications of age-related degradation in the piping and the header condition should be representative of the main piping. The type and frequency of the inspections are appropriate based on guidance provided by other GALL Report programs which manage aging of concrete, such as the Structures Monitoring Program. These programs suggest visual inspections with a frequency of at least every 5 years to detect degradation of concrete exposed to raw water. Based on its review, the staff finds that the applicant addressed the AERM adequately.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
Aging Management Review Results 3-368 3.3.2.3.5  Auxiliary Systems
- Component Cooling System
- Summary of 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 component cooling system component groups.
The staff's review did not find any line items indicating plant
-specific Notes F through J whereby the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report.
The staff's evaluation of the line items with generic notes A through E is documented in SER Section 3.3.2.1. 3.3.2.3.6  Auxiliary Systems
- Compressed Air System
- Summary of 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 compressed air system component groups.
The staff's evaluation for carbon and low
-alloy steel bolting exposed to groundwater and soil, which are being managed for loss of preload and loss of material by the Bolting Integrity Program, is documented in SER Section 3.3.2.3.4.
In LRA Tables 3.3.2-6 and 3.3.2
-23, the applicant stated that stainless steel heat exchanger components exposed to wetted air or gas are being managed for reduction of heat transfer due to fouling by the Periodic Inspection Program. The AMR line items cite generic note H. The AMR line items also cite plant
-specific Note 6, indicating that the Periodic Inspection Program is being applied to confirm that the internal environment remains sufficiently dry in order to preclude the effects of aging.
The staff reviewed the applicant's Periodic Inspection Program and its evaluation is documented in SER Section 3.0.3.3.2. The staff finds the applicant's program acceptable to manage aging for these components because stainless steel components exposed to dry air experience no aging effects and the program includes visual inspections which can detect reduction of heat transfer due to fouling and which will confirm that the wetted air or gas environment remains dry enough such that aging does not occur.
In LRA Table 3.3.2-6, the applicant stated that aluminum heat exchanger components for the SBO aftercooler externally exposed to indoor air or internally exposed to wetted air and gas are being managed for reduction of heat transfer due to fouling by the Periodic Inspection Program. The AMR line items cite generic note H for this item, indicating that the aging effect is not in the GALL Report for this component, material, and environment combination.
The staff reviewed the associated line items in the LRA and confirms that the applicant has identified the correct aging effects for this component, material, and environment combination because the GALL Report states that reduction of heat transfer results from fouling on heat transfer surfaces and that particulate fouling can be due to dust and corrosion products. The staff notes that the aluminum heat exchanger surfaces will be susceptible to this aging effect. The staff's evaluation of the applicant's Periodic Inspection Program is documented in SER Section 3.0.3.3.2. The staff finds the applicant's proposal to manage aging using the above program acceptable because the Periodic Inspection Program uses visual inspections, which Aging Management Review Results 3-369 are capable of detecting dust and corrosion products on the aluminum heat exchanger surfaces to manage reduction of heat transfer due to fouling.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.3.7  Auxiliary Systems
-Containment Ventilation System
- Summary of 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 ventilation system component groups.
The staff's evaluation of elastomer door seals and flexible connections exposed to wetted air or gas (internal) having an aging effect of hardening and loss of strength due to elastomer degradation that will be managed by the Periodic Inspection Program with generic note G is documented in SER Section 3.3.2.3.1.
The staff's evaluation of elastomer door seals and flexible connections exposed to air with treated borated water leakage for which the applicant cited generic note G is documented in SER Section 3.3.2.3.1.
3.3.2.3.8  Auxiliary Systems
-Control Area Ventilation System
- Summary of 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 control area ventilation system component groups.
The staff's evaluation of elastomer door seals and flexible connections exposed to wetted air or gas (internal) having an aging effect of hardening and loss of strength due to elastomer degradation that will be managed by the Periodic Inspection Program with generic note G is documented in SER Section 3.3.2.3.1.
3.3.2.3.9  Auxiliary Systems
-Cranes and Hoists
- Summary of 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 cranes and hoists system component groups.
The staff's review did not find any line items indicating plant
-specific notes F through J whereby the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report.
The staff's evaluation of the line items with nNotes A through E is documented in SER Section 3.3.2.1. 3.3.2.3.10 Auxiliary Systems
-Demineralized Water System
-Summary of Aging Management Evaluation
-LRA Table 3.3.2-10 Aging Management Review Results 3-370 The staff reviewed LRA Table 3.3.2-10, which summarizes the results of AMRs for the demineralized water system component groups.
The staff's evaluation for carbon and low
-alloy steel bolting exposed to groundwater and soil, which are being managed for loss of preload and loss of material by the Bolting Integrity Program, is documented in SER Section 3.3.2.3.4.
In LRA Table 3.3.2-10, the applicant stated that aluminum storage tanks for demineralized water exposed to soil are being managed for loss of material due to pitting, crevice, an d microbiologically
-influenced corrosion by the Aboveground Non
-Steel Tanks Program. The AMR line item cites generic note G for this item, indicating that the environment is not in the GALL Report for this component and material.
The staff reviewed the associated line items in the LRA and confirmed that the applicant has identified the correct aging effects for this component, material, and environment combination because, as noted in NUREG
-1833, "Technical Bases for Revision to the License Renewal Guidance Documents," steel in this environment is susceptible to the above notes aging mechanisms and aluminum will be similarly affected. The staff's evaluation of the applicant's Aboveground Non
-Steel Tanks Program is documented in SER Section 3.0.3.3.3. The staff finds the applicant's proposal to manage aging using the above program acceptable because the Aboveground Non
-Steel Tanks Program uses visual inspection and UT, which are able to detect loss of material due to pitting, crevice, and microbiologically
-influenced corrosion.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.3.11 Auxiliary Systems
-Emergency Diesel Generators and Auxiliary System
-Summary of 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 EDGs and auxiliary system component groups.
The staff's review did not find any line items indicating plant
-specific Notes F through J whereby the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report.
The staff's evaluation of the line items with notes A through E is documented in SER Section 3.3.2.1. 3.3.2.3.12 Auxiliary Systems
- Fire Protection System
- Summary of 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 fire protection system component groups.
In LRA Table 3.3.2-12, the applicant stated that grout fire barriers (penetration seals) exposed externally to indoor uncontrolled air and outdoor air are being managed for cracking due to shrinkage and freeze
-thaw and loss of material due to spalling and scaling by the Fire Aging Management Review Results 3-371 Protection and Structures Monitoring programs. The AMR line items cite generic note F. The AMR line items also cite plant
-specific Note 5, indicating that, based on industry standards and guidelines, grout is susceptible to cracking due to shrinkage in this environment. The AMR line items further cite plant
-specific Note 6, indicating that grout is susceptible to loss of material due to spalling and scaling and cracking due to freeze
-thaw in an outdoor air environment, consistent with industry guidance.
The staff reviewed the applicant's Fire Protection and Structures Monitoring programs and its evaluations are documented in SER Sections 3.0.3.2.5 and 3.0.3.2.15, respectively. The staff notes that the Fire Protection Program is used for other fire barriers such as penetration seals, walls, floors, and ceilings and that grout material is regularly used as a penetration seal to provide a fire barrier. The staff also notes that the applicant's Fire Protection Program provides for visual inspections of fire barriers once every 18 months for detection of cracking and loss of material and that since these materials serve the intended function of a fire barrier, the Fire Protection Program is an appropriate program to manage cracking and loss of material for these components. The staff further notes that the applicant's Structures Monitoring Program provides for periodic visual inspection of cracking and loss of material of concrete structures and penetrations at a frequency not to exceed 5 years and that since grout is similar in nature to concrete, the Structures Monitoring Program is an appropriate program to manage cracking and loss of material for grout.
The staff finds the applicant's currently proposed programs acceptable to manage loss of material and cracking for these components because (1) for this material in an environment of indoor uncontrolled and outdoor air, the aging effects are expected to be cracking due to shrinkage and freeze
-thaw and loss of material due to spalling and scaling; and (2) the periodic visual inspections performed by the Fire Protection and Structures Monitoring programs will confirm that there is no loss of material or cracking, or will result in a corrective action to assess the situation
. In LRA Table 3.3.2-12, the applicant stated that asbestos fire barriers (walls, ceiling, and floors) exposed to indoor air have no aging effects and no AMP is proposed. The AMR line item cites generic note J. The AMR line item also cites plant
-specific Note 14, which states:
Asbestos is a mineral fiber encased in an inorganic binder. The asbestos material is located in an air
-indoor environment [and] is not subject to significant aging effects. Asbestos materials do not experience aging effects unless exposed to temperatures, radiation, or chemical capable of attacking the specific inorganic chemical composition. Asbestos materials are selected for compatibility with the environment during the design.
Asbestos material in this non
-aggressive air environment is not expected to experience significant aging effects. This is consistent with plant operating experience.
The staff finds the applicant's proposal acceptable because the staff acknowledges that the use of asbestos as a fire barrier on walls, ceilings, and floors in power plant environments is a design-driven criterion and, once selected for the environment, will not have any significant age-related degradation. On the basis that the asbestos is not located in areas of high temperatures or radiation, the staff finds that the asbestos fire barrier will not have any AERMs in an indoor air environment.
 
Aging Management Review Results 3-372 In LRA Table 3.3.2-12, the applicant stated that fiberglass cloth fire barrier wraps exposed to indoor air and air with borated water leakage have no aging effect and no AMP is proposed. The AMR line items cite generic note J. The AMR line items also cite plant
-specific Note 15, which states:
Fiberglass cloth consists of inorganic fibers encased [in] a polymeric binder. The polymer material located in air-indoor or air with borated water leakage environment is not subject to significant aging effects. Polymer materials do not experience aging effects unless exposed to temperatures, radiation, or chemical capable of attacking the specific polymer chemical composition. Polymer materials are selected for compatibility with the environment during the design. Polymer material in these non
-aggressive air environments is not expected to experience significant aging effects. This is consistent with plant operating experience.
The staff finds the applicant's proposal acceptable because the staff acknowledges that the use of fiberglass in power plant environments is a design
-driven criterion and, once selected for the environment, will not have any significant age-related degradation. On the basis that the fiberglass cloth fire barrier wrap is not located in areas of high temperatures or radiation, the staff finds that the fiberglass cloth fire barrier wrap will not have any AERMs in indoor air or air with borated water leakage environments.
In LRA Table 3.3.2-12, the applicant stated that copper alloy spray nozzle and valve body components exposed to outdoor air are being managed for loss of material by the Fire Protection Program. The AMR line items cite generic note G, indicating that the environment is not in the GALL Report for these components and material.
The staff reviewed all AMR result line items in the GALL Report where the material is copper alloy and the aging effect/mechanism is loss of material and confirmed that for this environment, there are no entries in the GALL Report for this component and material.
The staff's evaluation of the applicant's Fire Protection Program is documented in SER Section 3.0.3.2.5. The staff finds the monitoring program acceptable because it uses visual inspections which are appropriate to determine whether there is any loss of component function caused by loss of material due to exposure to an outdoor air environment. The visual inspections are consistent with the GALL Report and thus, the monitoring program will adequately manage the aging effect.
In LRA Table 3.3.2-12, the applicant stated that copper alloy (greater than 15 percent Zinc) sprinkler head components exposed to outdoor air are being managed for loss of material by the Fire Water System Program. The AMR line item cites generic note G, indicating that the environment is not in the GALL Report for this component and material.
The staff reviewed all AMR result line items in the GALL Report where the material is copper alloy (greater than 15 percent Zinc) and the aging effect/mechanism is loss of material and confirmed that for this environment, there are no entries in the GALL Report for this component and material.
The staff's evaluation of the applicant's Fire Water System Program is documented in SER Section 3.0.3.2.6. The staff finds the monitoring program acceptable to manage aging for these Aging Management Review Results 3-373 components because it includes fire water system functional testing, flow tests, flushes, and testing of sprinkler heads or replacement every 50 years based on NFPA
-25 codes, which are appropriate to determine whether there is any loss of component function caused by loss of material due exposure to an outdoor air environment. The visual inspections are consistent with the GALL Report and thus, the monitoring program will adequately manage the aging effect.
The staff's evaluation for carbon and low
-alloy steel bolting exposed to groundwater and soil, which are being managed for loss of preload and loss of material by the Bolting Integrity Program, is documented in SER Section 3.3.2.3.4.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.3.13 Auxiliary Systems
- Fresh Water System
-Summary of 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 fresh water system component groups.
The staff's review did not find any line items indicating plant
-specific notes F through J whereby the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report.
The staff's evaluation of the line items with notes A through E is documented in SER Section 3.3.2.1. 3.3.2.3.14 Auxiliary Systems
- Fuel Handling and Fuel Storage System
-Summary of 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 fuel handling and fuel storage system component groups.
In LRA Table 3.3.2-14, the applicant stated that for new fuel storage racks made of treated wood externally exposed to indoor air, there are no AERMs. The applicant referenced generic note F for this item, indicating that this material is not in the GALL Report for this component. In plant-specific Note 4, the applicant further stated that wood components that are protected from a weather environment are not susceptible to loss of material or change in material properties (such as rot) unless the wood is in a moist location or exposed to sustained high temperatures.
The applicant indicated that the new fuel storage racks in the fuel handling building are not subjected to any of these conditions that would lead to aging effects. Therefore, the applicant did not assign an AMP for this component material and environment combination.
The staff evaluated the applicant's claim that there are no AERMs for this component, material, and environment combination and noted that the GALL Report does not describe the aging effects for wood. The staff also reviewed the available literature and determined that:  (1) by definition, treated wood is "wood that has been pressure treated with a preservative to improve the resistance of wood to destruction from fungi, insects and marine borers" (See Wood Handbook: Wood as an Engineering Material, Gen. Tech. Rep. FPL
-GTR-113, U.S. Department Aging Management Review Results 3-374 of Agriculture, Forest Service, Forest Products Laboratory, 1999); and (2) aging of wood can be curtailed if its exposure to heat and moisture are minimized or eliminated (See "Microbial Degradation of Wood," by R. I. Morris, in Uhlig's Corrosion Handbook, 2nd Edition, Edited by R. R. Winston, John Wiley & Sons, 2000). Based on its review of the LRA and available literature regarding the aging of wood, the staff finds the applicant's management of the wood storage racks acceptable because the wood product is specially treated against the effects of rot and the indoor air plant environment is not conducive to biotic degradation.
In LRA Table 3.3.2-14, the applicant stated that new polymer fuel storage rack components exposed to indoor air or air with borated water leakage (external) have no AERM and that for this component, material, and environment combination, no AMP is needed. The AMR line items cite generic note F, indicating that the material is not in the GALL Report for this component.
The staff reviewed all material entries in the GALL Report and confirmed that polymer material is not included in the GALL Report.
For these AMR results, the applicant also cited plant
-specific Note 8, stating that polymer materials located indoors and subject to an indoor air or air with borated water leakage environment is not subject to significant aging effects. The applicant further stated that polymer materials are located in non
-aggressive environments, but that aging effects could occur if exposed to temperature, radiation, or chemicals capable of attacking the specific polymer chemical composition. The applicant further stated that during design, these polymer materials are selected for compatibility so degradation in these environments is not expected to occur.
Based on its review of technical literature (e.g., Roff, W.J., Fibres, Plastics, and Rubbers: A Handbook of Common Polymers, Academic Press Inc., New York, 1956) and current industry research and operating experience related to polymer structural components, the staff has determined that, in the absence of specific environmental stressors such as ultraviolet light, high radiation, or ozone concentrations, structural components made of these materials do not exhibit aging effects of concern during the period of extended operation. The staff noted that new reactor fuel does not emit radiation appreciably above background and is not expected to create a radiation
-related environmental stressor for new fuel storage racks. The staff has determined that for appropriately selected polymer structural components in a plant indoor air or air with boron leakage environment, there are no aging effects that cause degradation of the components during the period of extended operation. On the basis that the subject components have no aging effects that cause degradation during the period of extended operation, the staff finds the applicant's AMR results for these components, indicating that there is no AERM and no AMP is needed, to be acceptable.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AM R results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.3.15 Auxiliary Systems
-Fuel Handling Ventilation System
-Summary of 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 fuel handling ventilation system component groups.
 
Aging Management Review Results 3-375 The staff's evaluation of elastomer door seals and flexible connections exposed to wetted air or gas (internal) having an aging effect of hardening and loss of strength due to elastomer degradation that will be managed by the Periodic Inspection Program with generic note G is documented in SER Section 3.3.2.3.1.
The staff's evaluation of elastomer door seals and flexible connections exposed to air with treated borated water leakage for which the applicant cited generic note G is documented in SER Section 3.3.2.3.1.
3.3.2.3.16 Auxiliary Systems
-Fuel Oil System
-Summary of 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 oil system component groups.
In LRA Table 3.3.2-16, the applicant stated that for polymer sight glasses exposed to fuel oil and indoor air, there is no aging effect and no AMP is proposed. The AMR line items cite generic note F, indicating that the material is not in the GALL Report for this component.
The staff reviewed all AMR result line items in the GALL Report where the environments are fuel and indoor air and confirmed that there are no entries for this component or material.
The staff notes that these line items are located in the fuel oil system and as such, would not be expected to be exposed to high radiation or ozone concentrations. The staff finds the applicant's proposal acceptable because based on its review of technical literature (e.g., Roff, W.J., Fibres, Plastics, and Rubbers: A Handbook of Common Polymers, Academic Press Inc., New York, 1956) and current industry research and operating experience related to plexiglass, the staff has determined that, in the absence of specific environmental stressors such as ultraviolet light, high radiation, or ozone concentrations, components made of these materials do not exhibit aging effects of concern during the period of extended operation. The staff determines that for polymer sight glasses in a plant indoor air environment or exposed to fuel oil, there are no aging effects that cause degradation of the components during the period of extended operation. On the basis that the subject components have no aging effects that cause degradation during the period of extended operation, the staff finds the applicant's AMR results for these components, indicating that there is no AERM and no AMP is needed, to be acceptable.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.3.17 Auxiliary Systems
- Heating Water and Heating Steam System
- Summary of Aging Management Evaluation
-LRA Tabl e 3.3.2-17 The staff reviewed LRA Table 3.3.2-17, which summarizes the results of AMR evaluations for the heating water and heating steam system component groups.
In LRA Table 3.3.2-17, the applicant stated that the carbon steel piping, fittings and valves exposed internally to closed
-cycle cooling water are being managed for wall thinning due to flow Aging Management Review Results 3-376 accelerated corrosion by the Flow
-Accelerated Corrosion Program. The AMR line items cited generic note H. The staff reviewed the associated line items in the LRA and confirmed the applicant has identified the correct aging effects for this component, material and environmental combination because, as stated in EPRI TR
-106611, "Flow
-Accelerated Corrosion in Power Plants," wall thinning can occur in demineralized or neutral water with low oxygen content, where there is flowing water or wet steam in carbon steel components with a temperature range from 190 &deg;F to 500 &deg;F. In addition, the staff notes that the loss of material due to other mechanisms for these components is addressed in other LRA line items through other AMPs.
The staff's evaluation of the applicant's Flow
-Accelerated Corrosion Program is documented in SER Section 3.0.3.2.1. Although the applicant cited generic note H, to indicate that this aging effect was not included in the GALL Report for this component, material and environment combination, the staff notes several items including item 3.4.1-29, which addresses wall thinning due to flow
-accelerated corrosion for comparable components in steam or treated water environments. The staff also notes that the heating water and heating steam system will be enhanced prior to the period of extended operation to institute a pure water control program in accordance with EPRI guidance, which will ensure environmental conditions comparable to other treated water systems. The staff finds the applicant's proposal to manage aging using the Flow-Accelerated Corrosion Program acceptable because the GALL Report recommends this AMP to manage the same aging effect for the combination of comparable components, materials and environment.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.3.18 Auxiliary Systems
-Nonradioactive Drain System
-Summary of Aging Management Evaluation
-LRA Table 3.3.2-18 The staff reviewed LRA Table 3.3.2-18, which summarizes the results of AMRs for the nonradioactive drain system component groups.
In LRA Tab le 3.3.2-18, the applicant stated that copper alloy valve body components exposed to outdoor air are being managed for loss of material by the Periodic Inspection Program. The AMR line item cites generic note G, indicating that the environment is not in the GALL Report for this component and material.
The staff reviewed all AMR result line items in the GALL Report where the material is copper alloy and the aging effect/mechanism is loss of material and confirmed that for this environment, there are no entries in the GALL Report for this component and material.
The staff's evaluation of the applicant's Periodic Inspection Program is documented in SER Section 3.0.3.3.2. The staff finds the monitoring program acceptable because it uses visual inspections which are appropriate to determine whether there is any loss of component function caused by loss of material due to exposure to an outdoor air environment. The visual inspections are consistent with the GALL Report and thus, the monitoring program will adequately manage the aging effect.
 
Aging Management Review Results 3-377 The staff's evaluation for carbon and low
-alloy steel bolting exposed to groundwater and soil, which are being managed for loss of preload and loss of material by the Bolting Integrity Program, is documented in SER Section 3.3.2.3.4. On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.3.19 Auxiliary Systems
-Radiation Monitoring System
-Summary of Aging Management Evaluation
-LRA Table 3.3.2-19 The staff reviewed LRA Table 3.3.2-19, which summarizes the results of AMR evaluations for the radiation monitoring system component groups.
The staff's evaluation for glass filter housings, sight glasses, flow elements, and tanks (sampling vessels and accumulators) exposed to air with borated water leakage, wetted air or gas, and closed-cycle cooling water, for which no aging effect and no AMP is proposed, is documented in SER Section 3.3.2.3.1.
3.3.2.3.20 Auxiliary Systems-Radioactive Drain System
-Summary of Aging Management Evaluation
-LRA Table 3.3.2-20 The staff reviewed LRA Table 3.3.2-20, which summarizes the results of AMR evaluations for the radioactive drain system component groups.
The staff's review did not find any line items indicating plant
-specific notes F through J whereby the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report.
The staff's evaluation of the line items with notes A through E is documented in SER Section 3.3.2.1. 3.3.2.3.21 Auxiliary Systems
- Radwaste System
- Summary of Aging Management Evaluation
-LRA Table 3.3.2-21 The staff reviewed LRA Table 3.3.2-21, which summarizes the results of AMR evaluations for the radwaste system component groups. The staff's review did not find any line items indicating plant
-specific Notes F through J whereby the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report.
The staff's evaluation of the line items with notes A through E is documented in SER Section 3.3.2.1. 3.3.2.3.22 Auxiliary Systems
- Sampling System
-Summary of Aging Management Evaluation
-LRA Table 3.3.2-22 Aging Management Review Results 3-378 The staff reviewed LRA Table 3.3.2-22, which summarizes the results of AMR evaluations for the sampling system component groups.
The staff's evaluation for glass filter housings, sight glasses, flow elements, and tanks (sampling vessels and accumulators) exposed to air with borated water leakage, wetted air or gas, and closed-cycle cooling water, for which no aging effect and no AMP is proposed, is documented in SER Section 3.3.2.3.1.
3.3.2.3.23 Auxiliary Systems
-Service Water System
-Summary of Aging Management Evaluation
-LRA Table 3.3.2-23 The staff reviewed LRA Table 3.3.2-23, which summarizes the results of AMR evaluations for the service water system component groups.
In LRA Table 3.3.2-23, the applicant stated that the nickel-alloy hoses exposed to raw water are being managed for fouling and loss of material due to pitting, crevice, and microbiologically-influenced corrosion by the Open-Cycle Cooling Water System Program. The AMR line item cites generic note H. This line item cites plant
-specific Note 9, which states that the aging effect/mechanism of loss of material due to pitting, crevice, and microbiologically
-influenced corrosion and fouling is not in the GALL Report for this component, material, and environment; however, it is applicable to this combination. Plant
-specific Note 9 also states that the Open-Cycle Cooling Water System Program is used to manage the aging effects for this component, material, and environment combination.
The staff reviewed the associated line items in the LRA and confirmed that the applicant has identified the correct aging effects for this component, material, and environment combination because loss of material, although rare and generally insignificant, may occur in nickel
-alloy components exposed to raw water, but other aging effects addressed by the GALL Report (e.g., cracking) are essentially unknown for this combination of material and environment.
The staff's evaluation of the applicant's Open
-Cycle Cooling Water System Program is documented in SER Section 3.0.3.1.9. The staff finds the applicant's proposal to manage aging using this AMP acceptable because (1) nickel
-alloy components exposed to raw water are not subject to any mechanisms which lead to loss of material which are not present in steel, (2) the rate of material loss from steel components when exposed to raw water is significantly greater than for nickel alloys, and (3) the GALL Report states that the Open
-Cycle Cooling Water System Program is an adequate means to manage aging of steel components exposed to raw water. Since the Open
-Cycle Cooling Water System Program is an acceptable means to manage the aging of a material which is more susceptible to loss of material than nickel alloys, the staff finds that this AMP will also be satisfactory in managing the aging of nickel alloys.
The staff's evaluation for reinforced concrete exposed to raw water, which is being managed for cracking, loss of bond, and loss of material (spalling, scaling)/corrosion of embedded steel by the Open-Cycle Cooling Water System Program, is documented in SER Section 3.3.2.3.4.
In LRA Table 3.3.2-23, the applicant stated that the loss of material due to crevice corrosion and reduction of heat transfer due to fouling for titanium heat exchanger components exposed to closed-cycle cooling water is not addressed by the GALL Report. The applicant cited generic note F for this item, indicating that the material is not in the GALL Report for this component. The applicant also stated that the aging effect is managed by the Closed
-Cycle Cooling Water System Program.
 
Aging Management Review Results 3-379 The staff confirmed that the GALL Report does not include an AERM or AMP for titanium alloy components exposed to a closed
-cycle cooling water environment.
The staff reviewed the applicant's Closed
-Cycle Cooling Water System Program evaluated in SER Section 3.0.3.2.3. The staff finds the monitoring program acceptable because(1) it performs condition monitoring, visual inspections, and NDEs to determine component functionality due to loss of material due to crevice corrosion and heat transfer due to fouling; and (2) the program is being enhanced to include a one
-time inspection in areas of stagnant flow. The condition monitoring, visual inspections, and NDEs are consistent with the GALL Report and thus, the monitoring program will adequately manage the aging effect.
In LRA Table 3.3.2-23, the applicant stated that titanium heat exchanger components exposed to closed-cycle cooling water (external) is not addressed by the GALL Report. The applicant cited generic note F for this item, indicating that no AMP is needed for this component, material, and environment combination. The applicant also stated that titanium material is corrosion resistant in water up to 260 C (500 &deg;F) due to a protective oxide film. The applicant further stated that this was consistent with plant operating experience and that no AMP is needed.
The staff confirms that the GALL Report does not include an AERM or AMP for titanium alloy components exposed to closed
-cycle cooling water (external) environments.
The staff further reviewed the applicant's component, material, and environment combination, as well as other items in Table 3.3.2-23. The staff determines that the applicant has also indicated a loss of material due to crevice corrosion and reduction of heat transfer due to fouling that can occur with this material, component, and environment. In that instance, the applicant identified the Closed
-Cycle Cooling Water Program as the AMP. The staff notes that based on multiple references (e.g., AZo Journal of Materials Online, Britannica Encyclopedia, Key to Metals Database (online) Article 24), t itanium is resistant to pitting, general, and crevice corrosion and SCC in salt water and turbine exhaust steam environments in essence due to its formation of very stable, continuous, highly adherent, and protective oxide films on metal surfaces. Based on these references, the staff also notes that due to its corrosion resistance capabilities, it is widely used in the refinery industry for condenser tubing and the aerospace industry in temperature applications up to 600 C. The staff finds the applicant's proposal that there are no other AERMs other than the reduction of heat transfer acceptable based on titanium's resistance to pitting, general, and crevice corrosion and SCC in closed-cycle cooling water. In LRA Table 3.3.2-23, the applicant stated that the reduction of heat transfer due to fouling and loss of material/macrofouling for titanium heat exchanger components exposed to raw water is not addressed by the GALL Report. The applicant cited generic note F for this item, indicating that the material is not in the GALL Report for this component. The applicant also stated that the aging effect is managed by the Open
-Cycle Cooling Water System Program.
The staff confirms that the GALL Report does not include an AERM or AMP for titanium alloy components exposed to a raw water (internal) environment.
The staff reviewed the applicant's Open
-Cycle Cooling Water System Program evaluated in SER Section 3.0.3.1.9. The staff finds the monitoring program acceptable because it uses performance monitoring, visual inspections, and NDEs to determine component function due to reduction of heat transfer due to fouling and loss of material/macrofouling. The program includes surveillance and control techniques to manage the aging effect. The performance Aging Management Review Results 3-380 monitoring, visual inspections, and NDEs are consistent with the GALL Report and thus, the monitoring programs will adequately manage the aging effect.
In LRA Table 3.3.2-23, the applicant stated that titanium heat exchanger components exposed to air indoor, dry air or gas (external), and air with borated water leakage is not addressed by the GALL Report. The applicant cited generic note F for this item, indicating that the material is not in the GALL Report for this component. The applicant also stated that no AMP is needed for this component, material, and environment combination. The applicant further stated that titanium material is corrosion resistant in water up to 260 C (500 &deg;F) due to a protective oxide film. The applicant stated that this was consistent with plant operating experience and that no AMP is needed.
The staff confirms that the GALL Report does not include an AERM or AMP for titanium alloy components exposed to indoor air, dry air or gas (external), and air with borated water leakage (external) environments. The staff's review indicates that no AMP is needed for this material in an air environment, as titanium alloys exhibit excellent corrosion resistance (general, pitting, and crevice) up to 260 C (500 &deg;F) due to a protective oxide film. The staff further notes that based on multiple references (e.g., AZo Journal of Materials Online, Britannica Encyclopedia, Key to Metals Database (online) Article 24), titanium is resistant to pitting, general, and crevice corrosion and SCC in salt water and turbine exhaust steam environments in essence due to its formation of very stable, continuous, highly adherent, and protective oxide films on metal surfaces. Based on these references, the staff also notes that due to its corrosion resistance capabilities, it is widely used in the refinery industry for condenser tubing and the aerospace industry in temperature applications up to 600 C. The staff finds the applicant's proposal that there are no other AERMs acceptable based on titanium's resistance to pitting, general, and crevice corrosion and SCC in indoor air, dry air or gas (external), and air with borated water leakage (external) environments.
In LRA Table 3.3.2-23, the applicant stated that the reduction of heat transfer due to fouling for titanium heat exchanger components exposed to lubricating oil is not addressed by the GALL Report. The applicant cited generic note F for this item, indicating that the material is not in the GALL Report for this component. The applicant also stated that the aging effect is managed by the One-Time Inspection and Lubricating Oil Analysis programs.
The staff confirms that the GALL Report does not include an AERM or AMP for titanium alloy components exposed to a lubricating oil environment.
The staff reviewed the applicant's use of the One
-Time Inspection and Lubricating Oil Analysis programs evaluated in SER Sections 3.0.3.1.11 and 3.0.3.2.12, respectively. The staff finds the monitoring programs acceptable because (1) they include analysis of oil to ensure that the physical properties of the lubricating oil are maintained within acceptable limits to ensure component intended function due to reduction of heat transfer due to fouling, and (2) the One-Time Inspection Program ensures the effectiveness of the Lubricating Oil Analys is Program. The One
-Time Inspection and Lubricating Oil Analysis programs are consistent with the GALL Report and thus, the monitoring programs will adequately manage the aging effect.
In LRA Table 3.3.2-23, the applicant stated that titanium heat exchanger components exposed to lubricating oil (external) is not addressed by the GALL Report. The applicant cited generic note F for this item, indicating that the material is not in the GALL Report for this component. The applicant also stated that titanium material is corrosion resistant in lubricating oil due to a Aging Management Review Results 3-3 81 protective oxide film and thus, no aging effect is observed. The applicant further stated that this was consistent with plant operating experience and that no AMP is needed.
The staff confirms that the GALL Report does not include an AERM or AMP for titanium alloy components exposed to lubricating oil environments.
The staff reviewed the applicant's component, material, and environment combination, as well as other items in Table 3.3.2-27. The staff determined that the applicant has also indicated a reduction of heat transfer due to fouling that can occur with this material, component, and environment. In that instance, the applicant identified the One
-Time Inspection and Lubricating Oil Analysis programs as the AMPs. Thus, although the material is corrosion resistant in this environment, the applicant also has AMPs to evaluate a potential aging effect. The staff's evaluation for copper alloy heat exchanger components exposed to wetted air and gas, which are being managed for reduction of heat transfer due to fouling by the Periodic Inspection Program and cite generic note G, is documented in SER Section 3.3.2.3.3.
The staff's evaluation for stainless steel heat exchanger components exposed to wetted air or gas, which are being managed for reduction of heat transfer due to fouling by the Periodic Inspection Program and cite generic note H, is documented in SER Section 3.3.2.3.6.
In LRA Table 3.3.2-23, the applicant stated that stainless steel bolting components exposed to raw water are being managed for loss of preload due to self
-loosening by the Bolting Integrity Program. The AMR line items reference generic note G. The staff reviewed the applicant's Bolting Integrity Program and its evaluation is documented in SER Section 3.0.3.2.2. The staff finds the applicant's program acceptable to manage aging for these components because (1) it has incorporated industry guidance on proper selection of bolting materials and lubricants and proper installation practices in order to prevent loss of preload from occurring, and (2) it includes detailed visual inspections of bolting which can detect if loss of preload due to self
-loosening is occurring.
The staff's evaluation for carbon and low
-alloy steel bolting exposed to groundwater and soil, which are being managed for loss of preload and loss of material by the Bolting Integrity Program, is documented in SER Section 3.3.2.3.4. In LRA Table 3.3.2-23, the applicant stated that carbon and low
-alloy steel bolting exposed externally to raw water is being managed for loss of preload due to thermal effects, gasket creep, and self
-loosening and loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion by the Bolting Integrity Program. The applicant also stated that stainless steel bolting exposed externally to raw water is being managed for loss of material due to pitting and crevice corrosion by the Bolting Integrity Program. The AMR line items cite generic note G. The staff reviewed the applicant's Bolting Integrity Program and its evaluation is documented in SER Section 3.0.3.2.2. The staff notes that the Bolting Integrity Program manages loss of material and loss of preload by performing visual inspections. The staff finds the applicant's proposed program for managing carbon, low
-alloy, and stainless steel bolting for loss of preload and loss of material acceptable because the visual inspections used by the Bolting Integrity Program are appropriate for detection of these agi ng mechanisms and the program has Aging Management Review Results 3-382 incorporated industry guidance on proper selection of bolting materials, lubricants, and installation torque.
In LRA Table 3.3.2-23, the applicant stated that carbon steel with copper alloy cladding heat exchanger components exposed internally to raw water are being managed for loss of material due to erosion by the Open
-Cycle Cooling Water System Program. The AMR line items cite generic note H. The applicant also stated that carbon steel with titanium cladding heat exchanger components exposed internally to raw water are being managed for loss of material due to macrofouling by the Open
-Cycle Cooling Water System Program. The AMR line items cite generic note F. The staff reviewed the applicant's Open
-Cycle Cooling Water System Program and its evaluation is documented in SER Section 3.0.3.1.9. The staff notes that the Open
-Cycle Cooling Water System Program manages loss of material by performing either visual inspections or NDEs and conducting maintenance inspections, preventive maintenance, and surveillance testing. The staff finds the applicant's management of carbon steel with either copper alloy cladding or titanium cladding heat exchanger components for loss of material acceptable because the visual inspections and NDEs used by the Open
-Cycle Cooling Water System Program are appropriate for detection of these aging effects.
In LRA Table 3.3.2-23, the applicant stated that carbon steel with titanium alloy cladding and carbon or low
-alloy steel with nickel
-alloy cladding heat exchanger components exposed internally to dry air or gas have no AERMs and no AMP is necessary. The AMR line item for the carbon steel with titanium alloy cladding components cite generic note F, and the AMR line item for the carbon or low
-alloy steel with nickel
-alloy cladding components cite generic note G. The applicant stated that the technical basis for determining that no aging effects would occur on the nickel
-alloy cladding is that similar items in the GALL Report for nickel alloys exposed to dry air or gas, such as item IV.E
-1, require no AMP. The applicant also stated that titanium alloy has superior resistance to corrosion in both air and water environments up to 260 C (500 &deg;F). The staff confirmed that titanium alloys are more resistant to corrosion than many materials and are only susceptible to corrosion in very low pH solutions and, therefore, titanium cladding is not expected to corrode under dry air conditions. The staff finds the applicant's determination that carbon steel with titanium alloy cladding or low
-alloy steel with nickel
-alloy cladding heat exchanger components exposed internally to dry air or gas do not require an AMP acceptable because aging effects are not expected to occur for these materials when exposed to dry air or gas. In LRA Table 3.3.2-23, the applicant stated that aluminum bronze bolting, with 8 percent or more aluminum, exposed externally to indoor air are being managed for loss of preload due to thermal effects, gasket creep, and self
-loosening and SCC by the Bolting Integrity Program. The AMR line items cite generic note F for this item, indicating that the material is not in the GALL Report for this component.
The staff reviewed the associated line items in the LRA and confirms that the applicant has identified the correct aging effects for this component, material, and environment combination because aluminum bronze bolting can have comparable loss of preload as other bolting material. In addition, plant
-specific operating experience identified cracking of the bolts associated with this line item. The staff's evaluation of the applicant's Bolting Integrity Program is documented in SER Section 3.0.3.2.2. The staff finds the applicant's proposal to manage aging using the proposed program acceptable because the Bolting Integrity Program employs Aging Management Review Results 3-383 visual inspection, which is consistent with the GALL Report for monitoring these aging degradations. In addition, as noted in the operating experience for the above program, as a result of finding broken bolts on the service water strainer, strainer inspections are being conducted every 3 years to preclude future failures.
In LRA Table 3.3.2-23, the applicant stated that aluminum heat exchanger components for the station air compressors
-intercoolers and aftercooler exposed externally to wetted air or gas are being managed for reduction of heat transfer due to fouling by the Periodic Inspection Program. The AMR line item cites generic note H for this item, indicating that the aging effect is not in the GALL Report for this component, material, and environment combination.
The staff reviewed the associated line items in the LRA and confirms that the applicant has identified the correct aging effects for this component, material, and environment combination because the GALL Report states that reduction of heat transfer results from fouling on heat transfer surfaces and that particulate fouling can be due to dust and corrosion products. The staff notes that the aluminum heat exchanger surfaces will be susceptible to this aging effect. The staff's evaluation of the applicant's Periodic Inspection Program is documented in SER Section 3.0.3.3.2. The staff finds the applicant's proposal to manage aging using the above program acceptable because the Periodic Inspection Program uses visual inspections, which are capable of detecting dust and corrosion products on the aluminum heat exchanger surfaces to manage reduction of heat transfer by fouling.
In LRA Table 3.3.2-23, the applicant stated that aluminum bronze strainer bodies, with 8 percent or more aluminum, exposed internally to raw water are being managed for loss of material due to selective leaching by the Selective Leaching of Materials Program. The LRA line item cites generic note F for this item, indicating that the material is not in the GALL Report for this component.
The staff reviewed the associated line items in the LRA and confirms that the applicant has identified the correct aging effect for this component, material, and environment combination because, as noted in NUREG-1833, "Technical Bases for Revision to the License Renewal Guidance Documents," aluminum bronze materials are susceptible to the selective leaching process. The staff's evaluation of the applicant's Selective Leaching of Materials Program is documented in SER Section 3.0.3.1.12. The staff finds the applicant's proposal to manage aging using the above program acceptable because the Selective Leaching of Materials Program uses visual inspection and hardness tests, which is consistent with the GALL Report, for monitoring this degradation mechanism.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.3.24 Auxiliary Systems-Service Water Ventilation System
-Summary of Aging Management Evaluation
-LRA Table 3.3.2-24 The staff reviewed LRA Table 3.3.2-24, which summarizes the results of AMR evaluations for the service water ventilation system component groups.
 
Aging Management Review Results 3-384 In LRA Table 3.3.2-24, the applicant stated that copper alloy (greater than 15 percent Zinc) bolting components exposed to outdoor air are being managed for loss of material by the Periodic Inspection Program. The AMR line item cites generic note G, indicating that the environment is not in the GALL Report for this component and material.
The staff reviewed all AMR result line items in the GALL Report where the material is copper alloy and the aging effect/mechanism is loss of material and confirms that for this environment, there are no entries in the GALL Report for this component and material.
The staff's evaluation of the applicant's Periodic Inspection Program is documented in SER Section 3.0.3.3.2. The staff finds the monitoring program acceptable because it uses visual inspections which are appropriate to determine whether there is any loss of component function caused by loss of material due to exposure to an outdoor air environment. The visual inspections are consistent with the GALL Report and thus, the monitoring program will adequately manage the aging effect.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.3.25 Auxiliary Systems
- Spent Fuel Cooling System
-Summary of Aging Management Evaluation
-LRA Table 3.3.2-25 The staff reviewed LRA Table 3.3.2-25, which summarizes the results of AMR evaluations for the spent fuel cooling system component groups.
The staff's review did not find any line items indicating plant
-specific notes F through J whereby the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report.
The staff's evaluation of the line items with Notes A through E is documented in SER Section 3.3.2.1. 3.3.2.3.26 Auxiliary Systems
-Switchgear and Penetration Area Ventilation System
-Summary of Aging Management Evaluation
-LRA Table 3.3.2-26 The staff reviewed LRA Table 3.3.2-26, which summarizes the results of AMR evaluations for the switchgear and penetration area ventilation system component groups.
The staff's evaluation of elastomer door seals and flexible connections exposed to wetted air or gas (internal) having an aging effect of hardening and loss of strength due to elastomer degradation that will be managed by the Periodic Inspection Program with generic note G is documented in SER Section 3.3.2.3.1.
The staff's evaluation of elastomer door seals and flexible connections exposed to air with treated borated water leakage for which the applicant cited generic note G is documented in SER Section 3.3.2.3.1.
 
====3.3.3 Conclusion====
 
Aging Management Review Results 3-385 The staff concludes that the applicant has provided sufficient information to demonstrate that the effects of aging for the auxiliary systems components within the scope of license renewal and subject to an AMR will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.4  Aging Management of Steam and Power Conversion Systems This Section of the SER documents the staff's review of the applicant's AMR results for the steam and power conversion system components and component groups of the following:
auxiliary feedwater system main condensate and feedwater system main condenser and air removal main steam system main turbine and auxiliaries system 3.4.1  Summary of Technical Information in the Application LRA Section 3.4 provides AMR results for the steam and power conversion system components and component groups. In LRA Table 3.4.1, "Summary of Aging Management Evaluations for Steam and Power Conversion," the applicant provided a summary comparison of its AMRs to those evaluated in the GALL Report for steam and power conversion system components and component groups.
The applicant's AMRs evaluated and incorporated plant
-specific and industry operating experience in the determination of AERMs from plant
-specific condition reports and discussions with site personnel and from the GALL Report and issues identified since its publication.
3.4.2  Staff Evaluation The staff reviewed LRA Section 3.4 to determine whether the applicant provided sufficient information to demonstrate that the effects of aging for steam and power conversion system components within the scope of license renewal and subject to an AMR will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
The staff conducted an onsite audit of AMPs to ensure the applicant's claim that certain AMPs were consistent with the GALL Report. The purpose of this audit was to examine the applicant's AMPs and related documentation and to verify the applicant's claim of consistency with the corresponding GALL Report AMPs. The staff did not repeat its review of the matters described in the GALL Report. The staff's evaluations of the AMPs are documented in SER Section 3.0.3. The staff reviewed the AMRs to confirm the applicant's claim that certain identified AMRs were consistent with the GALL Report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was Aging Management Review Results 3-386 applicable and that the applicant had identified the appropriate GALL Report AMRs. Details of the staff's evaluation are discussed in SER Sections 3.4.2.1 and 3.4.2.2.
The staff also reviewed the AMRs not consistent with or not addressed in the GALL Report. The review evaluated whether all plausible aging effects were identified and whether the aging effects listed were appropriate for the combination of materials and environments specified.
Details of the staff's evaluation are discussed in SER Section 3.4.2.3. For components which the applicant claimed were not applicable or required no aging management, the staff reviewed the AMR line items and the plant's operating experience to verify the applicant's claims.
Table 3.4-1 summarizes the staff's evaluation of components, aging effects or mechanisms, an d AMPs listed in LRA Section 3.4 and addressed in the GALL Report.
Table 3.4-1  Staff Evaluation for Steam and Power Conversion 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 piping, piping components, and piping elements exposed to steam or treated water (3.4.1-1) Cumulative fatigue damage TLAA, evaluated in accordance with 10 CFR 54.21(c) Yes TLAA Fatigue is a TLAA (see SER Section 3.4.2.2.1)
Steel piping, piping components, and piping elements exposed to steam (3.4.1-2) Loss of material due to general, pitting, and crevice corrosion Water Chemistry and One-Time Inspection Yes One-Time Inspection and Water Chemistry Consistent with the GALL Report (see SER Section 3.4.2.2.2(1))
Steel heat exchanger components exposed to treated water (3.4.1-3) Loss of material due to general, pitting, and crevice corrosion Water Chemistry and One-Time Inspection Yes One-Time Inspection and Water Chemistry Consistent with the GALL Report (see SER Section 3.4.2.2.2.(1))
Steel piping, piping components, and piping elements exposed to treated water (3.4.1-4) Loss of material due to general, pitting, and crevic e corrosion Water Chemistry and One-Time Inspection Yes One-Time Inspection and Water Chemistry Consistent with the GALL Report (see SER Section 3.4.2.2.2(1))
Steel heat exchanger components exposed to treated water (3.4.1-5) Loss of material due to general, pitting, crevice, and galvanic corrosion Water Chemistry and One-Time Inspection Yes One-Time Inspection and Water Chemistry Consistent with the GALL Report (see SER Section 3.4.2.2.9)
Steel and stainless steel tanks exposed to treated water (3.4.1-6) Loss of material due to general (steel only), pitting, and crevice corrosion Water Chemistry and One-Time Inspection Yes One-Time Inspection and Water Chemistry Consistent with the GALL Report (see SER Section 3.4.2.2.2(1))
 
Aging Management Review Results 3-387 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 lubricating oil (3.4.1-7) Loss of material due to general, pitting, and crevice corrosion Lubricating Oil Analysis and One-Time Inspection Yes One-Time Inspection and Lubricating Oil Analysis Consistent with the GALL Repor t (see SER Section 3.4.2.2.2(2))
Steel piping, piping components, and piping elements exposed to raw water (3.4.1-8) Loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion and fouling Plant-specific Yes Not applicabl e Not applicable to Salem (see SER Section 3.4.2.2.3)
Stainless steel and copper alloy heat exchanger tubes exposed to treated water (3.4.1-9) Reduction of heat transfer due to fouling Water Chemistry and One-Time Inspection Yes One-Time Inspection and
 
Water Chemistry Consistent with the GALL Report (see SER Section 3.4.2.2.4(1))
Steel, stainless steel, and copper alloy heat exchanger tubes exposed to lubricating oil (3.4.1-10) Reduction of heat transfer due to fouling Lubricating Oil Analysis and One-Time Inspection Yes One-Time Inspection and Lubricating Oil Analysis Consistent with the GALL Report (see SER Section 3.4.2.2.4(2))
Buried steel piping, piping components, piping elements, and tanks (with or without coating or wrapping) exposed to soil (3.4.1-11) Loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion Buried Piping and Tank Surveillance or Buried Piping and Tank Inspection No  Yes Buried Piping Inspection Consistent with the GALL Report (see SER Section 3.4.2.2.5(1))
Steel heat exchanger components exposed to lubricating oil (3.4.1-12) Loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion Lubricating Oil Analysis and One-Time Inspection Yes One-Time Inspection and Lubricating Oil Analysis Consistent with the GALL Report (see SER Section 3.4.2.2.5(2))
Stainless steel piping, piping components, and piping elements exposed to steam (3.4.1-13) SCC Water Chemistry and One-Time Inspection Yes Not applicable Not applicable to PWRs (see SER Section 3.4.2.2.6)
 
Aging Management Review Results 3-388 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, tanks, and heat exchanger components exposed to treated water
> 60 &deg;C (140 &deg;F) (3.4.1-14) SCC Water Chemistry and One-Time Inspection Yes One-Time Inspection and Water Chemistry Consistent with the GALL Report (see SER Section 3.4.2.2.6)
Aluminum and copper alloy piping, piping components, and piping elements exposed to treated water (3.4.1-15) Loss of material due to pitting and crevice corrosion Water Chemistry and One-Time Inspection Yes One-Time Inspection and Water Chemistry Consistent with the GALL Report (see SER Section 3.4.2.2.7(1))
Stainless steel piping, piping components, and piping elements; tanks; and heat exchanger components exposed to treated water (3.4.1-16) Loss of material due to pitting and crevice corrosion Water Chemistry and One-Time Inspection Yes One-Time Inspection and Water Chemistry Consistent with the GALL Report (see SER Section 3.4.2.2.7(1))
Stainless steel piping, piping components, and piping elements exposed to soil (3.4.1-17) Loss of material due to pitting and crevice corrosion Plant-specific Yes Not applicable Not applicable to Salem (see SER Section 3.4.2.2.7(2))
Copper alloy piping, piping components, and piping elements exposed to lubricating oil (3.4.1-18) Loss of material due to pitting and crevice corrosion Lubricating Oil Analysis and One-Time Inspection Yes Not applicable Not applicable to Salem (see SER Section 3.4.2.2.7(3))
Stainless steel piping, piping components, piping elements, and heat exchanger components exposed to lubricating oil (3.4.1-19) Loss of material due to pitting, crevice, and microbiologically
-influenced corrosion Lubricating Oil Analysis and One-Time Inspection Yes One-Time Inspection and Lubricating Oil Analysis Consistent with the GALL Report (see SER Section 3.4.2.2.8)
Steel tanks exposed to air-outdoor (external)
(3.4.1-20) Loss of material due to general, pitting, and crevice corrosion Aboveground Steel Tanks No Not applicable Not applicable to Salem (see SER Section 3.4.2.1.1)
 
Aging Management Review Results 3-389 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation High-strength steel closure bolting exposed to air with steam or water leakage (3.4.1-21) SCC and cracking due to cyclic loading Bolting Integrity No Not applicable Not applicable to Salem (see SER Section 3.4.2.1.1)
Steel bolting and closure bolting exposed to air with steam or water leakage, air
-outdoor (external), or air-indoor uncontrolled (external)
(3.4.1-22) Loss of material due to general, pitting, and crevice corrosion; loss of preload due t o thermal effects, gasket creep, and self-loosening Bolting Integrity No Bolting Integrity Consistent with the GALL Report Stainless steel piping, piping components, and piping elements exposed to closed-cycle cooling water > 60 &deg;C (140 &deg;F) (3.4.1-23) SC C Closed-Cycle Cooling Water System No Closed-Cycle Cooling Water System Consistent with the GALL Report Steel heat exchanger components exposed to closed-cycle cooling water (3.4.1-24) Loss of material due to general, pitting, crevice, and galvanic corrosion Closed-Cycle Cooling Water System No Not applicable Not applicable to Salem (see SER Section 3.4.2.1.1)
Stainless steel piping, piping components, piping elements, and heat exchanger components exposed to closed-cycle cooling water (3.4.1-25) Loss of material due to pitting and crevice corrosion Closed-Cycle Cooling Water System No Closed-Cycle Cooling Water System Consistent with the GALL Report Copper alloy piping, piping components, and piping elements exposed to closed-cycle cooling water (3.4.1-26) Loss of material due to pitting, crevice, and galvanic corrosion Closed-Cycle Cooling Water System No Not applicable Not applicable to Salem (see SER Section 3.4.2.1.1)
Steel, stainless steel, and copper alloy heat exchanger tubes exposed to close d-cycle cooling water (3.4.1-27) Reduction of heat transfer due to fouling Closed-Cycle Cooling Water System No Not applicable Not applicable to Salem (see SER Section 3.4.2.1.1)
 
Aging Management Review Results 3-390 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Steel external surfaces exposed to air-indoor uncontrolled (external), condensation (external), or air-outdoor (external)
(3.4.1-28) Loss of material due to general corrosion External Surfaces Monitoring No External Surfaces Monitoring Consistent with the GALL Report Steel piping, piping components, and piping elements exposed to steam or treated water (3.4.1-29) Wall thinning due to flow-accelerated corrosion Flow-Accelerated Corrosion No Flow-Accelerated Corrosion Consistent with the GALL Report Steel piping, piping components, and piping elements exposed to condensatio n (internal) or air-outdoor (internal)
(3.4.1-30) Loss of material due to general, pitting, and crevice corrosion Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components No Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Consistent with the GALL Report Steel heat exchanger components exposed to raw water (3.4.1-31) Loss of material due to general, pitting, crevice, galvanic, and microbiologically
 
-influenced corrosion and fouling Open-Cycle Cooling Water System No Not applicable Not applicable to Salem (see SER Section 3.4.2.1.1)
Stainless steel and copper alloy piping, piping components, and piping elements exposed to raw water (3.4.1-32) Loss of material due to pitting, crevice, and microbiologica lly-influenced corrosion Open-Cycle Cooling Water System No Not applicable Not applicable to Salem (see SER Section 3.4.2.1.1)
Stainless steel heat exchanger components exposed to raw water (3.4.1-33) Loss of material due to pitting, crevice, and microbiologically-influenced corrosion and fouling Open-Cycle Cooling Water System No Open-Cycle Cooling Water System, Fire Water System, and Periodic Inspection Consistent with the GALL Report (see SER Section 3.4.2.1.2)
Steel, stainless steel, and copper alloy heat exchanger tubes exposed to raw water (3.4.1-34) Reduction of heat transfer due to fouling Open-Cycle Cooling Water System No Not applicable Not applicable to Salem (see SER Section 3.4.2.1.1)
 
Aging Management Review Results 3-391 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements, or Amendments Staff Evaluation Copper alloy
> 15% Zn piping, piping components, and piping elements exposed to closed-cycle cooling water, raw water, or treated water (3.4.1-35) Loss of material due to selective leaching Selective Leaching of Materials No Selective Leaching of Materials Consistent with the GALL Report Gray cast iron piping, piping components, and piping elements exposed to soil, treated water, or raw water (3.4.1-36) Loss of material due to selective leaching Selective Leaching of Materials No Not applicable Not applicable to Salem (see SER Section 3.4.2.1.1)
Steel, stainless steel, and nickel
-based alloy piping, piping components, and piping elements exposed to steam (3.4.1-37) Loss of material due to pitting and crevice corrosion Water Chemistry No Water Chemistry Consistent with the GALL Report Steel bolting and external surfaces exposed to air with borated water leakage (3.4.1-38) Loss of material due to boric acid corrosion Boric Acid Corrosion No Boric Acid Corrosion Consistent with the GALL Report Stainless steel piping, piping components, and piping elements exposed to steam (3.4.1-39) SCC Water Chemistry No Water Chemistry Consistent with the GALL Report Glass piping elements exposed to air, lubricating oil, raw water, and treated water (3.4.1-40) None None NA Not applicable Not applicable to Salem (see SER Secti on 3.4.2.1.1)
Stainless steel, copper alloy, and nickel-alloy piping, piping components, and piping elements exposed to air
-indoor uncontrolled (external)
(3.4.1-41) None None NA None Consistent with the GALL Report
 
Aging Management Review Results 3-392 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 air
-indoor controlled (external)
(3.4.1-42) None None NA Not applicable Not applicable to Salem (see SER Section 3.4.2.1.1)
Steel and stainless steel piping, piping components, and piping elements in concrete (3.4.1-43) No ne None NA Not applicable Not applicable to Salem (see SER Section 3.4.2.1.1)
Steel, stainless steel, aluminum, and copper alloy piping, piping components, and piping elements exposed to gas (3.4.1-44) None None NA Not applicable Not applicable to Salem (see SER Section 3.4.2.1.1)
The staff's review of the steam and power conversion system component groups followed several approaches. One approach, documented in SER Section 3.4.2.1, discusses the staff's review of AMR results for components the applicant indicated are consistent with the GALL Report and require no further evaluation. Another approach, documented in SER Section 3.4.2.2, discusses the staff's review of AMR results for components the applicant indicated are consistent with the GALL Report and for which further evaluation is recommended. A third approach, documented in SER Section 3.4.2.3, discusses the staff's review of AMR results for components the applicant indicated are not consistent with or not addressed in the GALL Report. The staff's review of AMPs credited to manage or monitor aging effects of the steam and power conversion system components is documented in SER Section 3.0.3. 3.4.2.1  AMR Results That Are Consistent with the GALL Report LRA Section 3.4.2.1 identifies the materials, environments, AERMs, and the following programs that manage aging effects for the steam and power conversion system components:
Aboveground Non
-Steel Tanks Bolting Integrity Boric Acid Corrosion Buried Piping Inspection Closed-Cycle Cooling Water Syste m  External Surfaces Monitoring Flow Accelerated Corrosion Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Lubricating Oil Analysis One-Time Inspection Open-Cycle Cooling Water System
 
Aging Management Review Results 3-393  Periodic Inspection Selective Leaching of Materials TLAA  Water Chemistry LRA Tables 3.4.2-1 through 3.4.2
-5 summarize the AMRs for the steam and power conversion 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 had claimed consistency and for which the GALL Report does not recommend further evaluation, the staff performed an audit and review to determine whether the plant
-specific components in these GALL Report component groups were bounded by the GALL Report evaluation.
The applicant provided a note for each AMR line item. The notes describe how the information in the tables aligns with the information in the GALL Report. The staff audited those AMRs with Notes A through E, which indicate how the AMR was consistent with the GALL Report.
Note A indicates that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. The staff audited these line items to verify consistency with the GALL Report and the validity of the AMR for the site
-specific conditions.
Note B indicates that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report and confirmed that it had reviewed and accepted the identified exceptions to the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant was consistent with the AMP identified in the GALL Report and whether the AMR was valid for the site-specific conditions.
Note C indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the AMP identified by the GALL Report. This note indicates that the applicant was unable to find a listing of some system components in the GALL Report; however, the applicant identified a different component in the GALL Report that had the same material, environment, aging effect, and AMP as the component under review. The staff audited these line items to verify consistency with the GALL Report and determined whether the AMR line item of the different component applied to the component under review and whether the AMR was valid for the site
-specific conditions.
Note D indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report and confirmed whether the AMR line item of the different component was applicable to the component under review. The staff confirmed whether it had reviewed and accepted the exceptions to the GALL Report AMPs. It 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.
 
Aging Management Review Results 3-394 Note E indicates that the AMR line item is consistent with the GALL Report for material, environment, and aging effect, but a different AMP is credited. The staff audited these line items to verify consistency with the GALL Report and determined whether the identified AMP would manage the aging effect consistent with the AMP identified in the GALL Report and whether the AMR was valid for the site
-specific conditions.
The staff notes that in LRA Table 3.4.2-1, there are AMR line items for a stainless steel tank exposed to treated water. The staff also notes that the LRA does not have a line item for the tank material exposed to an air or wetted gas internal environment as would occur when the tank is partially full. The staff further notes that the LRA line items manage the aging of the tank internals using the Water Chemistry and One
-Time Inspection programs. The staff finds the existing line items acceptable because:  (1) the Water Chemistry Program will minimize contaminant concentrations and thus mitigate loss of material due to various corrosion mechanisms for tank internal surfaces at the fluid to air transition zone, and (2) the One-Time Inspection Program will provide reasonable assurance that an aging effect is not occurring or that the aging effect is occurring slowly enough to not affect a component's intended function.
The staff concludes that 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).
The staff audited and reviewed the information in the LRA. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The staff's evaluation follows.
3.4.2.1.1  AMR Results Identified as Not Applicable LRA Table 3.4.1, item 3.4.1
-20 addresses loss of material due to general, pitting, and crevice corrosion in steel tanks exposed to air
-outdoor (external). The applicant stated that this line item is not applicable because there are no steel tanks exposed to air
-outdoor (external) in the steam and power conversion system. The staff reviewed LRA Section s 2.3.4 and 3.4 and confirmed that the applicant's LRA does not have any AMR results for the steam and power conversion systems that include steel tanks exposed to air
-outdoor (external). The staff also reviewed the applicant's UFSAR and confirmed that no in-scope steel tanks exposed to air-outdoor (external) are present in the steam and power conversion systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.4.1, item 3.4.1
-21 addresses high
-strength steel closure bolting exposed to air with steam or water leakage in the steam and power conversion system. The GALL Report recommends the use of GALL AMP XI.M18, "Bolting Integrity," to manage cracking due to cyclic loading or SCC for this component group. The applicant stated that this item is not applicable because there is no high
-strength steel closure bolting in the steam and power conversion system. The staff reviewed LRA Sections 2.3.4 and 3.4 and confirmed that the applicant's LRA does not have any AMR results for the steam and power conversion system that includes high-strength steel closure bolting exposed to air with steam or water leakage. The staff reviewed the applicant's UFSAR and confirmed that no in
-scope high
-strength steel closure bolting exposed to air with steam or water leakage is present in the steam and power conversion system and, therefore, finds the applicant's determination acceptable.
 
Aging Management Review Results 3-395 LRA Table 3.4.1-1, item 3.4.1-24 addresses loss of material due to general, pitting, crevice, and galvanic corrosion for steel heat exchanger components exposed to closed
-cycle cooling water. The applicant stated that this item is not applicable because there are no steel heat exchanger components exposed to closed
-cycle cooling water in the steam and power conversio n systems. The staff reviewed LRA Sections 2.3.4 and 3.4 and confirmed that the applicant's LRA does not have any AMR results that included the corresponding components in the closed-cycle cooling water environment. The staff also reviewed the UFSAR and confirmed that no in-scope steel heat exchanger components exposed to closed
-cycle cooling water are present in applicable systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.4.1-1, item 3.4.1-26 addresses loss of material due to pitting, crevice, and galvanic corrosion for copper alloy piping, piping components, and piping elements exposed to closed-cycle cooling water. The applicant stated that this item is not applicable because there are no corresponding components exposed to closed
-cycle cooling water in the steam and power conversion systems. The staff reviewed LRA Sections 2.3.4 and 3.4 and confirmed that the applicant's LRA does not have any AMR results that included the corresponding components in the closed
-cycle cooling water environment. The staff also reviewed the UFSAR and confirmed that no in
-scope copper alloy piping, piping components, or piping elements exposed to closed
-cycle cooling water are present in applicable systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.4.1-1, item 3.4.1-27 addresses reduction in heat transfer due to fouling for steel, stainless steel, and copper alloy heat exchanger components exposed to closed
-cycle cooling water. The applicant stated that this item is not applicable because there are no corresponding components exposed to closed
-cycle cooling water in the steam and power conversion systems. The staff reviewed LRA Sections 2.3.4 and 3.4 and confirmed that the applicant's LRA does not have any AMR results that included the corresponding components in the closed-cycle cooling water environment. The staff also reviewed the UFSAR and confirmed that no in-scope steel, stainless steel, or copper alloy heat exchanger components exposed to closed-cycle cooling water are present in applicable systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.4.1-1, item 3.4.1-31 addresses loss of material due to general, pitting, crevice, galvanic, and microbiologically
-influenced corrosion for steel heat exchanger components exposed to raw water. The applicant stated that this item is not applicable because there are no steel heat exchanger components exposed to raw water in the steam and power conversion systems. The staff reviewed LRA Sections 2.3.4 and 3.4 and confirmed that the applicant's LRA does not have any AMR results that included the corresponding components in a raw water environment. The staff also reviewed the UFSAR and confirmed that no in
-scope steel heat exchanger components exposed to raw water are present in applicable systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.4.1-1, item 3.4.1-32 addresses loss of material due to pitting, crevice, and microbiologically
-influenced corrosion for stainless steel and copper alloy piping, piping components, and piping elements exposed to raw water. The applicant stated that this item is not applicable because there are no stainless steel or copper alloy piping, piping components, or piping elements exposed to raw water in the steam and power conversion systems. The staff reviewed LRA Sections 2.3.4 and 3.4 and confirmed that the applicant's LRA does not have any AMR results that included the corresponding components in a raw water environment. The staff also reviewed the UFSAR and confirmed that no in
-scope stainless steel or copper alloy piping, Aging Management Review Results 3-396 piping components, or piping elements exposed to raw water are present in applicable systems and, therefore, finds the applicant's determination acceptable. LRA Table 3.4.1-1, item 3.4.1-34 addresses reduction of heat transfer due to fouling for steel, stainless steel, and copper alloy heat exchanger tubes exposed to raw water. The applicant stated that this item is not applicable because there are no corresponding components exposed to raw water with an aging mechanism of reduction of heat transfer due to fouling in the steam and power conversion systems. The staff reviewed LRA Sections 2.3.4 and 3.4 and confirmed that the applicant's LRA does not have any AMR results that included the corresponding components in a raw water environment with the above noted aging effect. The staff also reviewed the UFSAR and confirmed that no corresponding in
-scope components exposed to raw water are present in applicable systems and, therefore, finds the applicant's determination acceptable.
LRA Table 3.4.1, item 3.4.1
-36 addresses gray cast iron piping, piping components, and piping elements exposed to soil, treated water, or raw water. The GALL Report recommends the use of GALL 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 line item was not applicable because there are no steam and power conversion system piping, piping components, and piping elements fabricated from gray cast iron and exposed to soil, treated water, or raw water. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant's LRA does not have any AMR results for the steam and power conversion system that include gray cast iron piping, piping components, and piping elements exposed to soil, treated water, or raw water. The staff also noted that a search of the applicant's UFSAR did not find any evidence of gray cast iron piping, piping components, and piping elements in the steam and power conversion system exposed to soil, treated water, or raw water. Based on its review of the LRA and UFSAR, the staff confirmed that there are no in
-scope gray cast iron piping, piping components, and piping elements exposed to soil, treated water, or raw water in the steam and power conversion system and, therefore, finds the applicant's determination acceptable.
LRA Table 3.4.1, item 3.4.1
-40 addresses glass piping elements exposed to air, lubricating oil, raw water, and treated water. The applicant stated that this line item is not applicable because there are no glass piping elements exposed to air, lubricating oil, raw water, or treated water in the steam and power conversion systems. The staff reviewed LRA Sections 2.3.4 and 3.4 and confirmed that the applicant's LRA does not have any AMR results for the steam and power conversion systems that include glass piping elements exposed to air, lubricating oil, raw water, and treated water.
The staff notes that the applicant stated that there is no AERM or recommended AMP for this material and component combination. The staff also notes that the GALL Report recommends that there is no AERM or AMP for this material and environment combination. The staff, therefore, finds the applicant's proposal that there is no AERM or AMP acceptable regardless of whether or not the material and environment combination exists in the steam and power conversion systems.
LRA Table 3.4.1, item 3.4.1
-42 addresses steel piping, piping components, and piping elements externally exposed to controlled indoor air. The applicant stated that this line item is not applicable because all indoor air was assumed to be uncontrolled for the purposes of license renewal. The staff reviewed LRA Sections 2.3.3 and 3.3 and confirmed that the applicant's LRA does have AMR results for steel piping, piping components, and piping elements externally exposed to indoor uncontrolled air and that those items are being managed by alternative line items applicable to indoor uncontrolled air. The staff, therefore, finds the applicant's Aging Management Review Results 3-397 determination acceptable because uncontrolled air is a more aggressive environment than controlled air and the items are being managed by appropriate alternative line items.
LRA Table 3.4.1, item 3.4.1
-43 addresses steel and stainless steel piping, piping components, and piping elements in concrete. The applicant stated that this line item is not applicable because the applicant does not have any steel and stainless steel piping, piping components, and piping elements exposed to concrete in the steam and power conversion systems. The applicant also stated that there is no AERM or recommended AMP for this material and component combination. The staff notes that the GALL Report recommends that there is no AERM or AMP for this material and environment combination.
The staff, therefore, finds the applicant's proposal that there is no AERM or AMP acceptable regardless of whether or not the material and environment combination exists in the steam and power conversion systems.
LRA Table 3.4.1, item 3.4.1
-44 addresses steel, stainless steel, aluminum, and copper alloy piping, piping components, and piping elements exposed to gas. The applicant stated that this line item is not applicable because the applicant does not have any steel, stainless steel, aluminum, or copper alloy piping, piping components, and piping elements exposed to gas in the steam and power conversion systems. The applicant also stated that there is no AERM or recommended AMP for this material and component combination. The staff notes that the GALL Report recommends that there is no AERM or AMP for this material and environment combination.
The staff, therefore, finds the applicant's proposal that there is no AERM or AMP acceptable regardless of whether or not the material and environment combination exists in the steam and power conversion systems.
3.4.2.1.2  Loss of Material Due to General, Pitting, Crevice, Galvanic, and Microbiologically
-Influenced Corrosion and Fouling LRA Table 3.4.1, item 3.4.1
-33 addresses stainless steel heat exchanger components exposed to raw water, which are being managed for loss of material due to general, pitting, crevice, galvanic, and microbiologically
-influenced corrosion and fouling. The LRA credits the Fire Water System Program to manage aging for stainless steel flow elements, heat exchanger components, piping and fittings, pump casings, restricting orifice, strainer bodies, thermowells, and valve bodies in the fire protection system. The GALL Report recommends GALL AMP XI.M20, "Open
-Cycle Cooling Water System," to ensure that these aging effects are adequately managed. The AMR line items cite generic note E. The AMR line items also cite plant
-specific Note 9, indicating that the Fire Water System Program is substituted to manage the aging effects applicable to this component type, material, and environment combination.
The staff reviewed the applicant's Fire Water System Program and its evaluation is documented in SER Section 3.0.3.2.6. In its review of components associated with Table 3.4-1, item 3.4.1-33, the staff noted that the Fire Water System Program proposes to manage aging for these components through the use of periodic flushing, system performance testing, volumetric examinations, and visual inspections. The staff also noted that GALL AMP XI.M20 relies on implementation of the recommendations of NRC GL 89
-13, which includes using preventive measures, periodic visual inspections, and performance testing to manage these aging effects and is only applicable for components exposed to cooling water that transfers heat from safety
-related components to the ultimate heat sink. The staff finds the LRA proposed AMP acceptable because:  (1) the proposed preventive measures, performance monitoring, and inspection methods are effective for managing loss of material; and (2) the components are in the fire protection system and are not included within the scope of NRC GL 89
-13.
Aging Management Review Results 3-398 The staff concludes that 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).
3.4.2.1.3  Conclusion for AMRs Consistent with the GALL Report The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing the associated aging effects. On the basis of its review, the staff concludes that the AMR results, which the applicant claimed to be consistent with the GALL Report, are consistent with the GALL Report AMRs. Therefore, the staff concludes that the applicant has demonstrated that the aging effects for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.4.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended LRA Section 3.4.2.2 provides further evaluation of aging management, as recommended by the GALL Report for the steam and power conversion system 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 material due to general, pitting, crevice, and microbiologically
-influenc ed corrosion and fouling reduction of heat transfer due to fouling loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion  cracking due to SCC loss of material due to pitting and crevice corrosion loss of material due to pitting, crevice, and microbiologically
-influenced corrosion loss of material due to general, pitting, crevice, and galvanic corrosion Quality Assurance for Aging Management of Nonsafety
-Related Components For component groups evaluated in the GALL Report for which the applicant claimed consistency with the GALL Report and for which the GALL Report recommends further evaluation, the staff audited and reviewed the applicant's evaluations to determine whether they adequately address those issues and reviewed the applicant's further evaluations against the Aging Management Review Results 3-399 criteria in SRP
-LR Section 3.4.2.2. The staff's review of the applicant's further evaluations follows. 3.4.2.2.1  Cumulative Fatigue Damage LRA Section 3.4.2.2.1 states fatigue is a TLAA as defined in 10 CFR 54.3. Furthermore, TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c). The applicant stated that the evaluation of metal fatigue as a TLAA for the auxiliary feedwater, component cooling, main condensate and feedwater, and main steam systems is discussed in LRA Section 4.3. The staff reviewed LRA Section 3.4.2.2.1 against the criteria in SRP
-LR Section 3.4.2.2.1, which states that fatigue of steam and power conversion system components is a TLAA as defined in 10 CFR 54.3 and that 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 the staff's recommended acceptance criteria and review procedures for reviewing these TLAAs in SRP
-LR Section 4.3, "Metal Fatigue Analysis."  The staff also reviewed LRA Section 3.4.2.2.1 and the applicant's AMR items referenced to this LRA Section against the staff's AMR items for evaluating cumulative fatigue damage as given in AMR item 1 in the GALL Report, Volume 1, Table 4 and the AMR items in Section VIII of the GALL Report, Volume 2, Revision 1 that derive from this GALL Report, Volume 1 AMR item.
With regard to LRA Table 3.4.1, item 3.4.1
-1, the staff noted that GALL AMR items VIII.B1
-10, VIII.D1-7, and VIII.G
-37 identify cumulative fatigue damage as an applicable aging effect for steel piping, piping components, and piping elements and recommends that the TLAA on metal fatigue be used to manage this aging effect. The applicant included an applicable line item in LRA Tables 3.4.2-1, 3.4.2-2, 3.4.2-4, and 3.3.2
-5 for steel piping and fittings that received implicit fatigue analysis calculations in accordance with design code requirements for ASME Code Section III Class 2 or 3 components or ANSI B31.1 components consistent with the recommendations in the SRP
-LR. Based on its review, the staff finds the applicant's AMR analysis on cumulative fatigue piping and fittings to be acceptable because it is consistent with the recommendations in SRP
-LR Section 3.4.2.2.1. The staff evaluates the TLAA analysis for the piping and fittings component in SER Section 4.3.3. Based on the programs identified, the staff concludes that the applicant meets the SR P-LR Section 3.4.2.2.1 criteria. For those items that apply to LRA Section 3.4.2.2.1, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.4.2.2.2  Loss of Material Due to General, Pitting, and Crevice Corrosion The staff reviewed LRA Section 3.4.2.2.2 against the criteria in SRP
-LR Section 3.4.2.2.2.
  (1) LRA Section 3.4.2.2.2, item 1 is referenced by LRA Table 3.4.1, items 3.4.1-2, 3.4.1-3, 3.4.1-4, and 3.4.1
-6 and addresses steel piping, piping components, piping elements, heat exchanger components, tanks, turbine casings, and steel components exposed to treated water or steam, which are being managed for loss of material due to general, pitting, and crevice corrosion by the Water Chemistry and One
-Time Inspection programs. The applicant addressed the further evaluation criteria of the SRP
-LR by stating that for the associated components in the auxiliary feedwater system, component Aging Management Review Results 3-400 cooling system, demineralized water system, main condensate and feedwater system, main condenser and air removal system, main steam system, RCS, sampling system, and steam generators, the Water Chemistry and One
-Time Inspection programs will be used to manage loss of material due to general, pitting, and crevice corrosion.
The staff reviewed LRA Section 3.4.2.2.2, item 1 against the criteria described in SRP-LR Section 3.4.2.2.2, item 1, which states that loss of material due to general, pitting, and crevice corrosion could occur for steel piping, piping components, piping elements, tanks, and heat exchanger components exposed to treated water and in steel piping, piping components, and piping elements exposed to steam. The SRP
-LR also states that the existing AMP relies on monitoring and control of water chemistry to mitigate degradation and that a one
-time inspection of selected components at susceptible locations is an acceptable method to verify the effectiveness of the water chemistry controls.
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 3.0.3.1.11, respectively. The staff noted that the applicant's One
-Time Inspection Program includes the determination of sample size based on an assessment of materials, environment, plausible aging effects and mechanisms, and operating experience and the identification of inspection locations based on the aging effect. In its review of components associated with items 3.4.1-2, 3.4.1-3, 3.4.1-4, and 3.4.1
-6, the staff finds the applicant's proposal to manage aging using the above programs acceptable because:  (a) the Water Chemistry Program will assure that contaminants are maintained below applicable limits which have been shown to limit loss of material due to general, pitting, and crevice corrosion, and (b) the One-Time Inspection Program will verify the effectiveness of the Water Chemistry Program by including samples in low or stagnant flow areas. 
  (2) LRA Section 3.4.2.2.2.2, referenced by LRA Table 3.4.1, item 3.4.1
-7, 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 the loss of material through examination of susceptible locations in steel piping, piping components, and piping elements exposed to lubricating oil.
The staff reviewed LRA Section 3.4.2.2.2.2 against the criteria in SRP
-LR Section 3.4.2.2.2, item 2, 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 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 contaminant control should be verified 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 lube oil chemistry control 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 3-401  The staff's evaluations of the applicant's Lubricating Oil Analysis and One
-Time Inspection programs are documented in SER Sections 3.0.3.2.12 and 3.0.3.1.11, respectively. In its review of components associated with item 3.4.1
-7, 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:  (a) the Lubricating Oil Analysis Program was determined to be consistent with the GALL Report, and (b) the applicant stated that the On e-Time Inspection Program will be used to examine steel, piping components, and piping elements to verify the effectiveness of the Lubricating Oil Analysis Program. This satisfies the acceptance criteria in SRP
-LR Section 3.4.2.2.2, item 2 and, therefore, the applicant's AMR is consistent with GALL Report item VIII.G
-35. Based on its review and evaluation of the programs identified above, the staff concludes that the applicant's programs satisfy SRP
-LR Section 3.4.2.2.2 criteria. For those line items that apply to LRA Section 3.4.2.2.2, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.4.2.2.3  Loss of Material Due to General, Pitting, Crevice, and Microbiologically
-Influenced Corrosion and Fouling The staff reviewed LRA Section 3.4.2.2.3 against the criteria in SRP
-LR Section 3.4.2.2.3.
LRA Section 3.4.2.2.3, associated with LRA Table 3.4.1, item 3.4.1
-8, addresses loss of material due to general, pitting, crevice, and microbiologically influenced corrosion, and fouling in steel piping, piping components, and piping elements exposed to raw water. The applicant stated that this line item is not applicable because this material, environment and aging effect does not exist in the plant. The staff reviewed LRA Sections 2.3.4 and 3.4, and the UFSAR and Technical Specifications and confirmed that no in
-scope steel piping, piping components, and piping elements exposed to raw water are present in the Steam and Power Conversions systems, LRA Sections 2.3.4 and, therefore, finds the applicant's determination acceptable. 3.4.2.2.4  Reduction of Heat Transfer Due to Fouling The staff reviewed LRA Section 3.4.2.2.4 against the criteria in SRP
-LR Section 3.4.2.2.4.
  (1) LRA Section 3.4.2.2.4, item 1 is referenced by LRA Table 3.4.1, item 3.4.1-9 and addresses stainless steel or copper alloy heat exchanger tubes exposed to a treated water environment, which are being managed for reduction in heat transfer due to fouling by the Water Chemistry 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 verify the effectiveness of the Water Chemistry Program to manage the reduction of heat transfer due to fouling in the auxiliary feedwater and component cooling systems.
The staff reviewed LRA Section 3.4.2.2.4, item 1 against the criteria in SRP
-LR Section 3.4.2.2.4, item 1, which states that reduction of heat transfer due to fouling could occur for stainless steel and copper alloy heat exchanger tubes exposed to treated water. The SRP-LR also states that the existing AMP relies on control of water chemistry to manage reduction of heat transfer due to fouling, but these controls may not Aging Management Review Results 3-402 always have been adequate to preclude fouling. The SRP
-LR further states that the effectiveness of the water chemistry control program should be verified and that a one-time inspection is an acceptable method to verify effectiveness.
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 3.0.3.1.11, respectively. In its review of components associated with item 3.4.1
-9, the staff finds the applicant's proposal to manage aging with the above programs acceptable because the Water Chemistry Program provides for periodic sampling of treated water to maintain contaminants at acceptable limits to preclude loss of heat transfer due to fouling. In addition, the One
-Time Inspection Program will verify the effectiveness of the Water Chemistry Program by determining sample sizes based on materials, environments, aging mechanisms, and operating experience and by identifying inspection locations and examination techniques, including acceptance criteria, based on the aging effects for which the components are being examined.
    (2) LRA Section 3.4.2.2.4.2, referenced by LRA Table 3.4.1, item 3.4.1
-10, addresses steel, stainless steel, and copper alloy heat exchanger tubes exposed to lubricating oil, which are being managed for reduction in heat transfer due to fouling 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 reduction in heat transfer through examination of susceptible locations in stainless steel heat exchanger tubes exposed to lubricating oil.
The staff reviewed LRA Section 3.4.2.2.4.2 against the criteria in SRP
-LR Section 3.4.2.2.4, item 2, which states that reduction of heat transfer due to fouling could occur for steel, stainless steel, and copper alloy heat exchanger tubes exposed to lubricating oil. The SRP
-LR also states that the existing AMP relies on monitoring and control of lube oil chemistry to mitigate reduction of heat transfer due to fouling. 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 contaminant control should be verified to ensure that fouling does not occur. The SRP-LR also states that the GALL Report recommends further evaluation of programs to verify the effectiveness of the lube oil chemistry control program for which a one
-time inspection of selected components at susceptible locations is an acceptable method to determine whether an aging effect is not occurring or an aging effect is progressing very slowly such that the component's intended function will be maintained during the period of extended operation. The staff's evaluations of the applicant's Lubricating Oil Analysis and One
-Time Inspection programs are documented in SER Sections 3.0.3.2.12 and 3.0.3.1.11, respectively. In its review of components associated with item 3.4.1
-10, 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: 
(a) the Lubricating Oil Analysis Program was determined to be consistent with the GALL Report, and (b) the applicant stated that the One
-Time Inspection Program will be used to examine steel, stainless steel, and copper alloy heat exchanger tubes to verify the effectiveness of the Lubricating Oil Analysis Program. This satisfies the acceptance criteria in SRP
-LR Section 3.4.2.2.4, item 2 and, therefore, the applicant's AMR is consistent with GALL Report item VIII.G
-12.
Aging Management Review Results 3-403 Based on its review and evaluation of the programs identified above, the staff concludes that the applicant's programs satisfy SR P-LR Section 3.4.2.2.4 criteria. For those line items that apply to LRA Section 3.4.2.2.4, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.4.2.2.5  Loss of Material Due to General, Pitting, Crevice, and Microbiologically
-Influenced Corrosion The staff reviewed LRA Section 3.4.2.2.5 against the criteria in SRP
-LR Section 3.4.2.2.5.
  (1) LRA Section 3.4.2.2.5.1 refers to Table 3.4.1, item 3.4.1
-11 and addresses loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion in steel piping, piping components, piping elements, and tanks with or without coating exposed to soil. The applicant stated that loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion in the steel piping, piping components, and piping elements exposed to soil in the auxiliary feedwater system and demineralized water system will be managed by the Buried Piping Inspection Program.
The staff reviewed LRA Section 3.4.2.2.5.1 against the criteria in SRP
-LR Section 3.4.2.2.5.1, which states that loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion could occur in steel piping, piping components, piping elements, and tanks, with or without coating or wrapping, in a soil environment.
The SRP-LR also states that the effectiveness of the buried piping and tanks inspection program should be verified to evaluate an applicant's inspection frequency and operating experience with buried components, ensuring that loss of material does not occur. The staff reviewed the applicant's Buried Piping Inspection Program, which is evaluated in SER Section 3.0.3.2.10. The staff finds that the credited program is acceptable because the Buried Piping Inspection Program relies on preventive measures such as coating and wrapping to mitigate corrosion and periodic visual inspections of external surfaces to identify coating degradation and, therefore, ensures that the loss of material aging effect will be adequately managed.
    (2) LRA Section 3.4.2.2.5.2, referenced by LRA Table 3.4.1, item 3.4.1
-12, addresses steel heat exchanger components exposed to lubricating oil, which are being managed for loss of material due to general, pitting, crevice, and microbiologically
-influenced 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 steel piping, piping components, piping elements, tanks, and heat exchanger components exposed to lubricating oil in the auxiliary feedwater system and RCS.
The staff reviewed LRA Section 3.4.2.2.5.2 against the criteria in SRP
-LR Section 3.4.2.2.5, item 2, which states that loss of material due to general, pitting, crevice, and microbiologically
-influenced corrosion could occur in steel heat exchanger components 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 Aging Management Review Results 3-404 always have been adequate to preclude corrosion; therefore, the effectiveness of lubricating oil contaminant control should be verified 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 lube oil chemistry control 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 3.0.3.2.12 and 3.0.3.1.11, respectively. In its review of components associated with item 3.4.1
-12, 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: 
(a) the Lubricating Oil Analysis Program was determined to be consistent with the GALL Report, and (b) 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 3.4.2.2.5, item 2 and, therefore, the applicant's AMR is consistent with GALL Report item VIII.G
-6. Based on its review and evaluation of the programs identified above, the staff concludes that the applicant's programs meet SRP
-LR Section 3.4.2.2.5 criteria. For those line items that apply to LRA Section 3.4.2.2.5, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.4.2.2.6  Cracking Due to Stress-Corrosion Cracking The staff reviewed LRA Section 3.4.2.2.6 against the criteria in SRP
-LR Section 3.4.2.2.6.
The staff reviewed LRA Section 3.4.2.2.6 against the criteria in SRP
-LR Section 3.4.2.2.6. LRA Section 3.4.2.2.6 addresses cracking due to stress corrosion cracking, stating that line item 3.4.1-13 is applicable to BWRs only and is not used for Salem, which is a PWR. This item pertains to SCC in stainless steel piping, piping components, and piping elements exposed to steam. The staff noted that the applicant's plant type is PWR and agrees that this line item is not applicable.
LRA Section 3.4.2.2.6 also refers to Table 3.4.1, item 3.4.1
-14 and addresses SCC in stainless steel piping, piping components, piping elements, heat exchanger components, steam generator components, and tanks exposed to treated water that is greater than 60&deg; C (140&deg; F) in the steam generators, demineralized water system, sampling system, auxiliary feedwater system, main condensate and feedwater system, and main steam system. The LRA states that the Water Chemistry Program and One
-Time Inspection Program will be implemented to manage the aging effect for these components except for the steam generator components. The applicant also indicated that the One
-Time Inspection Program is used to verify the effectiveness of the Water Chemistry Program for the components other than the steam generator components. In addition, as described in applicant's letter dated October 8, 2010, the revised LRA states that the aging effect of the steam generator components (Unit 2 SG feedwater rings, spray nozzles and inspection port diaphragms) are managed by the Water Aging Management Review Results 3-405 Chemistry Program and Steam Generator Tube Integrity Program. The applicant further stated that the Steam Generator Tube Integrity Program is used to verify the effectiveness of the Water Chemistry Program for the steam generator components.
The staff reviewed LRA Section 3.4.2.2.6 against the criteria in SRP
-LR Section 3.4.2.2.6, which states that cracking due to SCC could occur in the stainless steel piping, piping components, piping elements, tanks, and heat exchanger components exposed to treated water greater than 60&deg; C (140&deg; F) and for stainless steel piping, piping components, and piping elements exposed to steam.
The SRP-LR further states that the existing AMP relies on monitoring and control of water chemistry to manage the effects of aging. However, the SRP
-LR indicates that high concentrations of impurities at crevices and locations with stagnant flow conditions could cause SCC and, therefore, the GALL Report recommends that the effectiveness of the water chemistry program should be verified to ensure that SCC 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 SCC does not occur.
The staff reviewed the LRA and identified in Table 3.4.1, item 3.4.1
-14 and Tables 3.1.2-4, 3.3.2-10, 3.3.2-22, 3.4.2-1, 3.4.2-2, and 3.4.2
-4 that the applicant credited the Water Chemistry Program and One
-Time Inspection Program to manage SCC of stainless steel piping, piping components, piping elements, tanks, and heat exchanger components exposed to treated water greater than 60
&deg;C (140 &deg;F). In its review, the staff also identified that the applicant credited the Water Chemistry Program and Steam Generator Tube Integrity Program to manage SCC of the stainless steel steam generator components exposed to treated water greater than 60
&deg;C (140&deg; F). The staff reviewed the applicant's Water Chemistry Program, One
-Time Inspection Program and Steam Generator Tube Integrity Program. The staff's evaluations are documented in SER Sections 3.0.3.1.2, 3.0.3.1.11, and 3.0.3.1.8, respectively. The staff finds that the credited programs are adequate to manage the aging effect because:  (1) the Water Chemistry Program monitors the plant water chemistry control parameters against the established parameter limits and, if a parameter exceeds the limit, the program performs adequate actions such that the water chemistry control continues to mitigate the aging effect; (2) the One
-Time Inspection Program includes a one
-time inspection of selected components to verify the effectiveness of the Water Chemistry Program consistent with the GALL Report; (3) the on e-time inspection can ensure that significant degradation does not occur and that the component's intended function is maintained during the period of extended operation; (4) the Steam Generator Tube Integrity Program implements the inspections of secondary side upper internals, which include feedwater rings and spray nozzles, and the secondary side visual inspections as recommended in the EPRI Steam Generator Integrity Assessment Guidelines that the LRA references consistent with the GALL Report; and (5) the steam generator inspections are adequate to confirm the effectiveness of the Water Chemistry Program. On the basis of its review, the staff finds that the applicant's AMR results satisfied the acceptance criteria in SRP
-LR Section 3.4.2.2.6.
Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.4.2.2.6 criteria. For those items that apply to LRA Section 3.4.2.2.6, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.4.2.2.7  Loss of Material Due to Pitting and Crevice Corrosion The staff reviewed LRA Section 3.4.2.2.7 against the criteria in SRP
-LR Section 3.4.2.2.7.
 
Aging Management Review Results 3-406  (1) LRA Section 3.4.2.2.7, item 1 is referenced by Table 3.4.1, items 3.4.1-6, 3.4.1-15, and 3.4.1-16 and addresses aluminum, copper alloy, and stainless steel piping, piping components, piping elements, tanks, and heat exchanger components 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 applicant addressed the further evaluation criteria of the SRP-LR by stating that, for the components exposed to treated water in the auxiliary feedwater system, chemical and volume control system, component cooling system, demineralized water system, main condensate and feedwater system, main condenser and air removal system, main steam system, RCS, sampling system, and steam generators, the Water Chemistry and One-Time Inspection programs will be used to manage loss of material due to pitting and crevice corrosion.
The staff reviewed LRA Section 3.4.2.2.7, item 1 against the criteria described in SRP-LR Section 3.4.2.2.7, item 1, which states that loss of material due to pitting and crevice corrosion could occur for stainless steel, aluminum, and copper alloy piping, piping components, and piping elements and for stainless steel tanks and heat exchanger components exposed to treated water. The SRP
-LR also states that the existing AMP relies on monitoring and control of water chemistry to mitigate degradation and that a one
-time inspection of selected components at susceptible locations is an acceptable method to verify the effectiveness of the chemistry control program. 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 3.0.3.1.11, respectively. The staff notes that the applicant's One
-Time Inspection Program includes the determination of sample size based on an assessment of materials, environment, plausible aging effects and mechanisms, and operating experience and the identification of inspection locations is based on the aging effect. In its review of components associated with items 3.4.1-6, 3.4.1-15, and 3.4.1
-16, the staff finds the applicant's proposal to manage aging using the above programs acceptable because:  (a) the Water Chemistry Program will assure that contaminants are maintained below applicable limits which have been shown to minimize corrosion, and (b) the One-Time Inspection Program will verify the effectiveness of the Water Chemistry Program by including samples from low or stagnant flow areas.
In addition to the above components, in its review of components associated with item 3.4.1-16, in LRA Table 3.1.2-4, the staff noted that the applicant proposed to manage aging for the stainless steel steam generator tube support plates exposed to treated water greater than 140
&deg; F for loss of material due to pitting and crevice corrosion through the Steam Generator Tube Integrity and Water Chemistry programs. The applicant stated that this was consistent with the GALL Report for material, environment, and aging effect, but a different AMP was credited. However, as noted above for item 3.4.1-16, the GALL Report recommends that the effectiveness of the water chemistry controls be verified through a one
-time inspection, and it was unclear to the staff how the Steam Generator Tube Integrity Program would be used to verify the effectiveness of the Water Chemistry Program. By letter dated June 17, 2010, the staff issued RAI 3.4.1-01, requesting that the applicant provide the basis for using the Steam Generator Tube Integrity Program to verify the effectiveness of the Water Chemistry Program. In its response dated July 15, 2010, the applicant revised the above line item to be consistent with the GALL Report to indicate that the One
-Time Inspection Program would be used to verify the effectiveness of the Water Chemistry Program for this line item.
Aging Management Review Results 3-407  However, after additional discussions with the staff on September 9, 2010, the applicant submitted additional information by letter dated October 8, 2010, regarding various steam generator components. The applicant revised LRA Section 3.4.2.2.7 item 1 by removing steam generators from the discussion regarding the use of the One
-Time Inspection Program to verify the effectiveness of the Water Chemistry Program, and added a discussion regarding the use of the Steam Generator Tube Integrity Program to verify water chemistry effectiveness for components in the steam generators. In addition, the applicant revised LRA Table 3.4.1 item 3.4.1-16 and LRA Table 3.1.2-4 for loss of material due to pitting and crevice corrosion in stainless steel steam generator components to reflect comparable information.
The staff finds the applicant's response and changes to the LRA acceptable because the Steam Generator Tube Integrity Program includes preventive measures to mitigate degradation related to corrosion phenomena and condition monitoring activities through inservice inspections of steam generator tube supports and internals to detect degradation including loss of material. Based on the above, the staff's concern described in RAI 3.4.1-01 is resolved.
  (2) LRA Section 3.4.2.2.7 item 2, associated with LRA Table 3.4.1, item 3.4.1
-17, addresses loss of material due to pitting and crevice corrosion for stainless steel piping, piping components, and piping elements exposed to soil. The applicant stated that this line item is not applicable because the stainless steel piping, piping components, and piping elements external surfaces in the Steam and Power Conversion System are not exposed to soil. The staff reviewed LRA Sections 2.3.4 and 3.4, and UFSAR and confirmed that no in
-scope stainless steel piping, piping components, and piping elements exposed to soil] are present in the Steam and Power Conversion System and, therefore, finds the applicant's determination acceptable.
  (3) LRA Section 3.4.2.2.7 item 3, associated with LRA Table 3.4.1, item 3.4.1
-18, addresses loss of material due to pitting and crevice corrosion and could occur for copper alloy piping, piping components, and piping elements exposed to lubricating oil. The applicant stated that this line item is not applicable because there are no copper alloy piping, piping components, and piping elements exposed to lubricating oil in the Steam and Power Conversion System. The staff reviewed LRA Sections 2.3.4 and 3.4, and UFSAR and confirmed that no in
-scope copper alloy piping, piping components, and piping elements exposed to lubricating oil are present in the Steam and Power Conversion System and, therefore, finds the applicant's determination acceptable.
Based on its review and evaluation of the programs identified above, the staff concludes that the applicant's programs meet SRP
-LR Section 3.4.2.2.7 criteria. For those line items that apply to LRA Section 3.4.2.2.7, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.4.2.2.8  Loss of Material Due to Pitting, Crevice, and Microbiologically
-Influenced Corrosion The staff reviewed LRA Section 3.4.2.2.8 against the criteria in SRP
-LR Section 3.4.2.2.8.
LRA Section 3.4.2.2.8, referenced by LRA Table 3.4.1, item 3.4.1
-19, addresses stainless steel piping, piping components, piping elements, and heat exchanger components exposed to Aging Management Review Results 3-408 lubricating oil, which are being managed for loss of material due to pitting, crevice, and microbiologically
-influenced 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, piping components, piping elements, and heat exchanger components exposed to lubricating oil.
The staff reviewed LRA Section 3.4.2.2.8 against the criteria in SRP
-LR Section 3.4.2.2.8, which states that loss of material due to pitting, crevice, and microbiologically
-influenced corrosion could occur in stainless steel piping, piping components, piping elements, and heat exchanger components 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 contaminant control should be verified 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 lube oil chemistry control 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 3.0.3.2.12 and 3.0.3.1.11, respectively. In its review of components associated with item 3.4.1
-19, 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:  (1) the Lubricating Oil Analysis Program was determined to be consistent with the GALL Report, and (2) 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 3.4.2.2.8 and, therefore, the applicant's AMR is consistent with GALL Report items VIII.G-3 and VIII.A
-9. Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.4.2.2.8 criteria. For the line items that apply to LRA Section 3.4.2.2.8, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effect of aging will be adequately managed so that the intended function(s) will be maintained with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.4.2.2.9  Loss of Material Due to General, Pitting, Crevice, and Galvanic Corrosion LRA Section 3.4.2.2.9 is referenced by LRA Table 3.4.1, item 3.4.1-5 and addresses loss of material due to general, pitting, crevice, and galvanic corrosion for steel heat exchanger components exposed to treated water, which are being managed by the Water Chemistry 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 verify the effectiveness of the Water Chemistry Program for steel heat exchanger components in the main condensate and feedwater system.
 
Aging Management Review Results 3-409 The staff reviewed LRA Section 3.4.2.2.9 against the criteria in SRP
-LR Section 3.4.2.2.9, which states that loss of material due to general, pitting, crevice, and galvanic corrosion can occur for steel heat exchanger components exposed to treated water. The SRP-LR also states that the existing AMP relies on control of water chemistry to manage this aging effect, but control of water chemistry does not preclude this aging effect at locations of stagnant flow conditions. The SRP-LR further states that the effectiveness of the water chemistry control program should be verified to ensure that corrosion does not occur and that a one
-time inspection of selected components at susceptible locations is an acceptable method to verify the program's effectiveness.
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 3.0.3.1.11, respectively. In its review of items associated with item 3.4.1-5, the staff finds the applicant's proposal to manage aging using the above programs acceptable because:  (1) the Water Chemistry Program provides for periodic sampling of treated water to maintain contaminants at acceptable limits to preclude corrosion, and (2) the One
-Time Inspection Program will verify the effectiveness of the Water Chemistry Program by determining sample sizes based on materials, environments, aging mechanisms, and operating experience and by identifying inspection locations and examination techniques, including acceptance criteria, based on the aging effects for which the components are being examined. Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.4.2.2.9 criteria. For those line items that apply to LRA Section 3.4.2.2.9, t he staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.4.2.2.10 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.
3.4.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report In LRA Tables 3.4.2-1 through 3.4.2
-5, 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 3.4.2-1 through 3.4.2
-5, the applicant indicated, via Notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report. The applicant provided further information concerning how the aging effects will be managed. Specifically, Note F indicates that the material for the AMR line item component is not evaluated in the GALL Report. Note G indicates that the environment for the AMR line item component and material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR line item component, material, and environment combination is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the line item component, material, and environment combination is not applicable. Note J indicates that neither the component nor the material and environment combination for the line item is evaluated in the GALL Report.
 
Aging Management Review Results 3-410 For component type, material, and environment combinations not evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine whether the applicant has demonstrated that the aging effects will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation. The staff's evaluation is discussed in the following sections.
3.4.2.3.1  Steam and Power Conversion System
-Auxiliary Feedwater System
-Summary of Aging Management Evaluation
-LRA Table 3.4.2-1 The staff reviewed LRA Table 3.4.2-1, which summarizes the results of AMRs for the auxiliary feedwater system component groups.
The staff's evaluation for stainless steel tanks exposed externally to soil, which are being managed for loss of material due to pitting, crevice, and microbiologically
-influenced corrosion by the Aboveground Non
-Steel Tanks Program and cite generic note G, is documented in SER Section 3.3.2.3.2.
3.4.2.3.2  Steam and Power Conversion System
-Main Condensate and Feedwater System-Summary of Aging Management Evaluation
-LRA Table 3.4.2-2 The staff reviewed LRA Table 3.4.2-2, which summarizes the results of AMR evaluations for the main condensate and feedwater system component groups.
The staff's review did not find any line items indicating plant
-specific Notes F through J whereby the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report.
The staff's evaluation of the line items with Notes A through E is documented in SER Section 3.4.2.1. 3.4.2.3.3  Steam and Power Conversion System
-Main Condenser and Air Removal System-Summary of Aging Management Evaluation
-LRA Table 3.4.2-3 The staff reviewed LRA Table 3.4.2-3, which summarizes the results of AMRs for the main condenser and air removal system component groups.
The staff's review did not find any line items indicating plant
-specific Notes F through J whereby the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report.
The staff's evaluation of the line items with Notes A through E is documented in SER Section 3.4.2.1. 3.4.2.3.4  Steam and Power Conversion System
-Main Steam System
-Summary of Aging Management Evaluation
-LRA Table 3.4.2-4 The staff reviewed LRA Table 3.4.2-4, which summarizes the results of AMRs for the main steam system component groups.
 
Aging Management Review Results 3-411 The staff's review did not find any line items indicating plant
-specific Notes F through J whereby the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report.
The staff's evaluation of the line items with Notes A through E is documented in SER Section 3.4.2.1. 3.4.2.3.5  Steam and Power Conversion System
-Main Turbine and Auxiliaries System
-Summary of Aging Management Evaluation
-LRA Table 3.4.2-5 The staff reviewed LRA Table 3.4.2-5, which summarizes the results of AMRs for the main turbine and auxiliaries system component groups.
In LRA Table 3.4.2-5, the applicant stated that aluminum valve bodies exposed to lubricating oil are being managed for loss of material due to pitting, crevice, and microbiologically
-influenced corrosion by the Lubricating Oil Analysis and One
-Time Inspection programs. The AMR line item cites generic note G for this item, indicating that the environment is not in the GALL Report for this component and material.
The staff reviewed the associated line items in the LRA and confirmed that the applicant has identified the correct aging effect for this component, material, and environment combination because, as noted in NUREG
-1833, "Technical Bases for Revision to the License Renewal Guidance Documents," aluminum is susceptible to this set of aging mechanisms in fuel oil environments. As such, aluminum would be comparably susceptible in lubricating oil environments. The staff's evaluations of the applicant's Lubricating Oil Analysis and One
-Time Inspection programs are documented in SER Sections 3.0.3.2.12 and 3.0.3.1.11, respectively. The staff finds the applicant's proposal to manage aging with the above programs acceptable because:  (1) the Lubricating Oil Analysis Program provides for periodic sampling to maintain contaminants at limits shown to preclude corrosion, and (2) the effectiveness of this program will be verified with the One
-Time Inspection Program, which determines the sample size based on materials, fabrication, environment, plausible aging mechanism, and operating experience and identifies inspection locations and examination techniques based on aging effect.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
====3.4.3 Conclusion====
The staff concludes that the applicant has provided sufficient information to demonstrate that the effects of aging for the steam and power conversion system components within the scope of license renewal and subject to an AMR will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
Aging Management Review Results 3-412 3.5  Aging Management of Containments, Structures, and Component Supports This Section of the SER documents the staff's review of the applicant's AMR results for the containments, structures, and component supports of the following:
auxiliary building component supports commodity group containment structure fire pump house fuel handling building office buildings penetration areas pipe tunnel piping and component insulation commodity group SBO compressor building service building service water accumulator enclosures service water intake shoreline protection and dike switchyard turbine building yard structures 3.5.1  Summary of Technical Information in the Application LRA Section 3.5 provides AMR results for the containment, structures, and component supports groups. LRA Table 3.5-1, "Summary of Aging Management Evaluations for Structures and Component Supports," is a summary comparison of the applicant's AMRs with those evaluated in the GALL Report for the structures and component supports 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.
3.5.2  Staff Evaluation The staff reviewed LRA Section 3.5 to determine whether the applicant provided sufficient information to demonstrate that the effects of aging for the structures and component supports 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 a review of the AMR items that the applicant had identified as being consistent with the GALL Report 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 Aging Management Review Results 3-413 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 3.5.2.1. The staff also conducted a review of 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 3.5.2.2 acceptance criteria. The staff's evaluations are documented in SER Section 3.5.2.2. 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 3.5.2.3. For SSCs which the applicant claimed were not applicable or required no aging management, the staff reviewed the AMR line items and the plant's operating experience to verify the applicant's claims.
Table 3.5-1 summarizes the staff's evaluation of components, aging effects or mechanisms, and AMPs listed in LRA Section 3.5 and addressed in the GALL Report.
Table 3.5-1 Staff Evaluation for Structures and Component Supports 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 PWR Concrete (Reinforced and Prestressed) and Steel Containments Concrete elements:  walls, dome, basemat, ring girder, buttresses, containment (as applicable)
(3.5.1-1) Aging of accessible and inaccessible concrete areas due to aggressive chemical attack and corrosion of embedded steel ISI (IWL) and for inaccessible concrete, an examination of representative samples of below-grade concrete and periodic monitoring of groundwater if environment is non-aggressive. A plant-specific program is to be evaluated if environment is aggressive.
Yes ASME Section XI, SubSection IWL and Structures Monitoring Program Consistent with the GALL Report (see SER Section 3.5.2.2.1(1))
 
Aging Management Review Results 3-414 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 Concrete elements:  all (3.5.1-2) Cracks and distortion due to increased stress levels from settlement Structures Monitoring. If a dewatering system is relied upon for control of settlement, then the licensee is to ensure proper functioning of the dewatering system through the period of extended operation.
Yes Structures Monitoring Program and ASME Section XI, SubSection IWL Consistent with the GALL Report (see SER Section 3.5.2.1.7 and 3.5.2.2.1(2))
Concrete elements:  foundation, subfoundation (3.5.1-3) Reduction in foundation strength, cracking, and differential settlement due to erosion of porous concrete subfoundation Structures Monitoring. If a dewatering system is relied upon to control erosion of cement from porous concrete subfoundations, then the licensee is to ensure proper functioning of the dewatering system through the period of extended operation.
Yes Not applicable Not applicable to Salem (see SER Section 3.5.2.2.1(2))
Concrete elements:  dome, wall, basemat, ring girder, buttresses, containment, concrete fill
-in annulus (as applicable)
(3.5.1-4) Reduction of strength and modulus of concrete due to elevated temperature A plant-specific AMP is to be evaluated.
Yes Not applicable Not applicable to Salem (see SER Section 3.5.2.2.1(3))
Steel elements:
drywell; torus; drywell head; embedded shell an d sand pocket regions; drywell support skirt; torus ring girder; downcomers; liner plate, ECCS suction header, support skirt, region shielded by diaphragm floor, suppression chamber (as applicable)
(3.5.1-5) Loss of material due to general, pitting, and crevice corrosion ISI (IWE) and 10 CFR Part 50, Appendix J Yes Not applicable Not applicable to PWRs (see SER Section 3.5.2.1.1)
 
Aging Management Review Results 3-415 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 elements:  steel liner, liner anchors, integral attachments (3.5.1-6) Loss of material due to general, pitting, and crevice corrosion ISI (IWE) and 10 CFR Part 50, Appendix J Yes ASME Section XI, SubSection IWE and 10 CFR 50, Appendix J Consistent with the GALL Report (see SER Section 3.5.2.2.1(4))
Prestressed containment tendons (3.5.1-7) Loss of prestress due to relaxation, shrinkage, creep, and elevated temperature TLAA, evaluated in accordance with 10 CFR 54.21(c) Yes Not applicable Not applicable to Salem (see SER Section 3.5.2.1.1 and 3.5.2.2.1(5))
Steel and stainless steel elements:  vent line, vent header, vent line bellows; downcomers (3.5.1-8) Cumulative fatigue damage (CLB fatigue analysis exists)
TLAA, evaluated in accordance with 10 CFR 54.21(c) Yes Not applicable Not applicable to PWRs (see SER Sections 3.5.2.1.1 and 3.5.2.2.1(6))
Steel, stainless steel elements, dissimilar metal welds:  penetration sleeves, penetration bellows; suppression pool shell, unbraced downcomers (3.5.1-9) Cumulative fatigue damage (CLB fatigue analysis exists)
TLAA, evaluated in accordance with 10 CFR 54.21(c) Yes Not applicable Not applicable to Salem (see SER Section 3.5.2.2.1(6))
Stainless steel penetration sleeves, penetration bellows, dissimilar metal welds (3.5.1-10) Cracking due to SCC ISI (IWE) and 10 CFR Part 50, Appendix J and additional
 
appropriate examinations/ evaluations for bellows assemblies and dissimilar metal welds. Yes Not applicable Not applicable to Salem (see SER Section 3.5.2.2.1(7))
Stainless steel vent line bellows (3.5.1-11) Cracking due to SCC ISI (IWE) and 10 CFR Part 50 , Appendix J and additional appropriate examination/
evaluation for bellows assemblies and dissimilar metal welds. Yes Not applicable Not applicable to PWRs (See SER Section 3.5.2.1.1 and 3.5.2.2.1(7))
 
Aging Management Review Results 3-416 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements , or Amendments Staff Evaluation Steel, stainless steel elements, dissimilar metal welds:  penetration sleeves, penetration bellows; suppression pool shell, unbraced downcomers (3.5.1-12) Cracking due to cyclic loading ISI (IWE) and 10 CFR Part 50, Appendix J and supplemented to detect fine cracks Yes Not applicable Not applicable to Salem (see SER Section 3.5.2.2.1(8))
Steel, stainless steel elements, dissimilar metal welds:  torus; vent line; vent header; vent line bellows; downcomers (3.5.1-13) Cracking due to cyclic loading ISI (IWE) and 10 CFR Part 50, Append ix J and supplemented to detect fine cracks Yes Not applicable Not applicable to PWRs (see SER Section 3.5.2.1.1 and 3.5.2.2.1(8))
Concrete elements:  dome, wall, basemat ring girder, buttresses, containment (as applicable)
(3.5.1-14) Loss of material (scaling, cracking, and spalling) due to freeze-thaw ISI (IWL). Evaluation is needed for plants that are located in moderate to severe weathering conditions (weathering index > 100 day-inch/yr) (NUREG-1557). Yes ASME Section XI, SubSection IWL Consistent with the GALL Report (see SER Section 3.5.2.2.1(9))
Concrete elements:  walls, dome, basemat, ring girder, buttresses, containment, concrete fill
-in annulus (as applicable)
(3.5.1-15) Cracking due to expansion and reaction with aggregate; increase in porosity and permeability due to leaching of calcium hydroxide ISI (IWL) for accessible areas.
None for inaccessible areas if concrete was constructed in accordance with the recommendations in ACI 201.2R. Yes ASME Section XI, SubSection IWL Consistent with the
 
GALL Report (see SER Section 3.5.2.2.1(10))
Seals, gaskets, and moisture barriers (3.5.1-16) Loss of sealing and leakage through containment due to deterioration of joint seals, gaskets, and moisture barriers (caulking, flashing, and other sealants)
ISI (IWE) and 10 CFR Part 50, Appendix J No ASME Section XI, SubSection IWE and 10 CFR Part 50, Appendix J Consistent with the GALL Report
 
Aging Management Review Results 3-417 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 Personnel airlock, equipment hatch and CRD hatch locks, hinges, and closure mechanisms (3.5.1-17) Loss of leak tightness in closed position due to mechanical wear of locks, hinges, and closure mechanisms 10 CFR Part 50, Appendix J and plant TSs No 10 CFR Part 50, Appendix J Consistent with the GALL Report Steel penetration sleeves and dissimilar metal welds; personnel airlock, equipment hatch, and CRD hatch (3.5.1-18) Loss of material due to general, pitting, and crevice corrosion ISI (IWE) and 10 CFR Part 50, Appendix J No ASME Section XI, SubSection IWE and 10 CFR Part 50, Appendix J Consistent with the GALL Report Steel elements:  stainless steel suppression chamber shell (inner surface)
(3.5.1-19) Cracking due to SCC ISI (IWE) and 10 CFR Part 50, Appendix J No Not applicable Not applicable to PWRs (see SER Section 3.5.2.1.1)
Steel elements:  suppression chamber liner (interior surface)
(3.5.1-20) Loss of material due to general, pitting, and crevice corrosion ISI (IWE) and 10 CFR Part 50, Appendix J No Not applicable Not applicable to PWRs (see SER Section 3.5.2.1.1)
Steel elements:  drywell head and downcomer pipes (3.5.1-21) Fretting or lockup due to mechanical wear ISI (IWE) No Not applicable Not applicable to PWRs (see SER Section 3.5.2.1.1)
Prestressed containment:  tendons and anchorage components (3.5.1-22) Loss of material due to corrosion ISI (IWL) No Not applicable Not applicable to Salem (see SER Section 3.5.2.1.1)
Safety-Related and Other Structures and Component Supports All Groups except Group 6:  interior and above-grade exterior concrete (3.5.1-23) Cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel Structures Monitoring Yes, if not within the scope of the Structures Monitoring Program Structures Monitoring Program and Fire Protectio n Consistent with the GALL Report (see SER Sections 3.5.2.1.9 and 3.5.2.2.2(1))
All Groups except Group 6:  interior and above-grade exterior concrete (3.5.1-24) Increase in porosity and permeability, cracking, and loss of material (spalling, scaling) due to aggressive chemical attack Structures Monitoring Yes, if not within the scope of the Structures Monitoring Program Structures Monitoring Program Consistent with the GALL Report (see SER Section 3.5.2.2.2(1))
 
Aging Management Review Results 3-418 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 All Groups except Group 6:  steel components:  all structural steel (3.5.1-25) Loss of material due to corrosion Structures Monitoring. If protective coatings are relied upon to manage the effects of aging, the Structures Monitoring Program is to include provisions to address protective coating monitoring and maintenance.
Yes, if not within the scope of the Structures Monitoring Program Structures Monitoring Program and Protective Coating Monitoring and Maintenance Program Consistent with the GALL Report (see SER Section 3.5.2.2.2(1))
All Groups except Group 6:  accessible and inaccessible concrete:
foundation (3.5.1-26) Loss of material (spalling, scaling) and cracking due to freeze-thaw Structures Monitoring. Evaluation is needed for plants that are located in moderate to severe weathering conditions (weathering index
 
> 100 day-inch/yr) (NUREG-1557). Yes, if not within the scope of the Structures Monitoring Program, or for inaccessible areas located in moderate to severe weathering conditions Structures Monitoring Program and Fire Protection Consistent with the GALL Report (see SER Sections 3.5.2.1.9 and 3.5.2.2.2(1))
All Groups except Group 6:  accessible and inaccessible interior/exterior concrete (3.5.1-27) Cracking due to expansion due to reaction with aggregates Structures Monitoring. None for inaccessible areas if concrete was constructed in accordance with the recommendations in ACI 201.2R-77. Yes, if not within the scope of the Structures Monitoring Program.
No for inaccessible areas if concrete was constructed in accordance with recommendations in ACI 201.2R-77 Not applicable Not applicable to Salem (see SER Sections3.5.2.2.2(1) and 3.5.2.2.2(2))
 
Aging Management Review Results 3-419 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements , or Amendments Staff Evaluation Groups 1-3, 5-9:  All (3.5.1-28) Cracks and distortion due to increased stress levels from settlement Structures Monitoring. If a dewatering system is relied upon for control of settlement, then the licensee is to ensure proper functioning of the dewatering system through the period of extended operation.
Yes, if not within the scope of the Structures Monitoring Program, or a dewatering system is relied upon Structures Monitoring Program and Fire Protection Consistent with the GALL Report (see SER Sections 3.5.2.1.7, 3.5.2.2.2(1) and 3.5.2.2.2(2))
Groups 1-3, 5-9:  foundation (3.5.1-29) Reduction in foundation strength, cracking, and differential settlement due to erosion of porous concrete subfoundation Structures Monitoring. If a dewatering system is relied upon for control of settlement, then the licensee is to ensure proper functioning of the dewatering system through the period of exte nded operation.
Yes, if not within the scope of the Structures Monitoring Program, or a dewatering system is relied upon Not applicable Not applicable to Salem (see SER Sections 3.5.2.2.2(1) and 3.5.2.2.2(2))
Group 4:  radial beam seats in BWR drywell; RP V support shoes for PWRs with nozzle supports; steam generator supports (3.5.1-30) Lockup due to wear ISI (IWF) or Structures Monitoring Yes, if not within the scope of the Structures Monitoring Program ASME Section XI, SubSection IWF Consistent with the GALL Report (see SER Section 3.5.2.2.2(1))
Groups 1-3, 5, 7-9:  below-grade concrete components, such as exterior walls below grade and foundation (3.5.1-31) Increase in porosity and permeability, cracking, loss of material (spalling, scaling), and aggressive chemical attack; cracking, loss of bond, loss of material (spalling, scaling), and corrosion of embedded steel Structures Monitoring. Examination of representative samples of below-grade concrete and periodic monitoring of groundwater, if the environment is non-aggressive.
A plant-specific program is to be evaluated if environment is aggressive.
Yes, if environment is aggressive Structures Monitoring Program and Buried Non-Steel Piping Inspection Consistent with the GALL Report (see SER Sections 3.5.2.1.8 and 3.5.2.2.2(2))
 
Aging Management Review Results 3-420 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements , or Amendments Staff Evaluation Groups 1-3, 5, 7-9:  exterior above
- and below-grade reinforced concrete foundations (3.5.1-32) Increase in porosity and permeability and loss of strength due to leaching of calcium hydroxide Structures Monitoring for accessible areas. None for inaccessible areas if concrete was constructed in accordance with the recommendations in ACI 201.2R-77. Yes, if for inaccessible areas concrete was not constructed in accordance with ACI 201.2R-77 Structures Monitoring Program Consistent with the GALL Report (see SER Section 3.5.2.2.2(2))
Groups 1-5:  concrete (3.5.1-33) Reduction of strength and modulus due to elevated temperature A plant-specific AMP is to be evaluated Yes, if temperature limits are exceeded Not applicable Not applicable t o Salem (see SER Section 3.5.2.2.2(3))
Group 6:  concrete; all (3.5.1-34) Increase in porosity and permeability, cracking, and loss of material due to aggressive chemical attack; cracking, loss of bond, and loss of material due to corrosion of embedded st eel Inspection of Water-Control Structures or Federal Energy Regulatory Commission (FERC)/U.S. Army Corps of Engineers dam inspections and maintenance programs and for inaccessible concrete, an examination of representative samples of below-grade concrete and periodic monitoring of groundwater, if the environment is non-aggressive.
A plant-specific program is to be evaluated if environment is aggressive.
Yes, if environment is aggressive RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants; Structures Monitoring Program; and Buried Non-Steel Piping Inspection Consistent with the GALL Report (see SER Sections 3.5.2.1.8and 3.5.2.2.2(4))
 
Aging Management Review Results 3-421 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements , or Amendments Staff Evaluation Group 6:  exterior above- and below-grade concrete foundation (3.5.1-35) Loss of material (spalling, scaling) and cracking due to freeze-thaw Inspection of Water-Control Structures or FERC/U.S. Army Corps of Engineers dam inspections and maintenance programs.
Evaluation is needed for plants that are located in moderate to severe weathering conditions (weathering index
> 100 day-inch/yr) (NUREG-1557). Yes, for inaccessible areas located in moderate to severe weathering conditions RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants and Structures Monitoring Progr am Consistent with the GALL Report (see SER Section 3.5.2.2.2(4))
Group 6:  all accessible and inaccessible reinforced concrete (3.5.1-36) Cracking due to expansion/ reaction with aggregates For accessible areas, inspection of Water-Control Structures or FERC/U.S. Army Corps of Engineers dam inspections and maintenance programs. None for inaccessible areas if concrete was constructed in accordance with the recommendations in ACI 201.2R-77. Yes, if for inaccessible areas concrete was not constructed in accordance with ACI 201.2R-77 Not applicable Not applicable to Salem (see SER Section 3.5.2.2.2(4)
) Group 6:  exterior above- and below-grade reinforced concrete foundation interior slab (3.5.1-37) Increase in porosity and permeability and loss of strength due to leaching of calcium hydroxide For accessible areas, Inspection of Water-Control Structures or FERC/U.S. Army Corps of Engineers dam inspections and maintenance programs. None for inaccessible areas if concrete was constructed in accordance with the recommendations in ACI 201.2R-77. Yes, if for inaccessible areas concrete was not constructed in accordance with ACI 201.2R-77 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants; Structures Monitoring Program; and Open-Cycle Cooling Water System Consistent with the GALL Report (see SER Sections 3.5.2.1.8 and 3.5.2.2.2(4))
 
Aging Management Review Results 3-422 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements , or Amendments Staff Evaluation Groups 7, 8:  tank liners (3.5.1-38) Cracking due to SCC; loss of material due to pitting and crevice corrosion A plant-specific AMP is to be evaluated. Yes Not applicable Not applicable to Salem (see SER Sections 3.5.2.1.1 and  3.5.2.2.2(5))
Support members; welds; bolted connections; support anchorage to building structure (3.5.1-39) Loss of material due to general and pitting corrosion Structures Monitoring  Yes, if not within the scope of the Structures Monitoring Program Structures Monitoring Program Consistent with the GALL Report (see SER Section 3.5.2.2.2(6))
Building concrete at locations of expansion and grouted anchors; grout pads for support base plates (3.5.1-40) Reduction in concrete anchor capacity due to local concrete degradation, service-induced cracking, or other concrete aging mechanisms Structures Monitoring Yes, if not within the scope of the Structures Monitoring Program Structure s Monitoring Program Consistent with the GALL Report (see SER Section 3.5.2.2.2(6))
Vibration isolation elements (3.5.1-41) Reduction or loss of isolation function, radiation hardening, temperature, humidity, and sustained vibratory loading Structures Monitoring  Yes, if not within the scope of the Structures Monitoring Program Structures Monitoring Program Consistent with the GALL Report (see SER Section 3.5.2.2.2(6))
Groups B1.1, B1.2, and B1.3:  support members:  anchor bolts, welds (3.5.1-42) Cumulative fatigue damage (CLB fatigue analysis exists)
TLAA, evaluated in accordance with 10 CFR 54.21(c) Yes Not applicable Not applicable to Salem (see SER Section 3.5.2.2.2(7))
Groups 1-3, 5, 6:  all masonry block walls (3.5.1-43) Cracking due to restraint shrinkage, creep, and aggressive environment Masonry Wall No Masonry Wall Program, Structures Monitoring Program, and Fire Protection Consistent with the GALL Report Group 6:  elastomer seals, gaskets, and moisture barriers (3.5.1-44) Loss of sealing due to deterioration of seals, gaskets, and moisture barriers (caulking, flashing, and other sealants)
Structures Monitoring No Structures Monitoring Program  Consistent with the GALL Report
 
Aging Management Review Results 3-423 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements , or Amendments Staff Evaluation Group 6:  exterior above- and below-grade concrete foundation; interior slab (3.5.1-45) Loss of material due to abrasion and cavitation Inspection of Water-Control Structures or FERC/U.S. Army Corps of Engineers dam inspections and maintenance No RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants; Structures Monitoring Program; and Open-Cycle Cooling Water System Consistent with the GALL Report (see SER Section 3.5.2.1.8)
Group 5:  fuel pool liners (3.5.1-46) Cracking due to SCC; loss of material due to pitting and crevice corrosion Water Chemistry and monitoring of spent fuel pool water level in accordance with TSs and leakage from the leak chase channels.
No Water Chemistry Consistent with the GALL Report Group 6:  all metal structural members (3.5.1-47) Loss of material due to general (steel only), pitting, and crevice corrosion Inspection of Water-Control Structures or FERC/U.S. Army Corps of Engineers dam inspections and maintenance. If protective coatings are relied upon to manage aging, protective coating monitoring and maintenance provisions should be included.
No RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants and Structures Monitoring Program Consistent with the GALL Report (see SER Section 3.5.2.1.5)
Group 6:  earthen water control structures - dams, embankments, reservoirs, channels, canals, and ponds (3.5.1-48) Loss of material and loss of form due to erosion, settlement, sedimentation, frost action, waves, currents, surface runoff, and seepage Inspection of Water-Control Structures or FERC/U.S. Army Corps of Engineers dam inspections and maintenance programs No RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants and Structures Monitoring Program Consistent with the GALL Report Support members; welds; bolted connections; support anchorage to building structure (3.5.1-49) Loss of material due to general, pitting, and crevice corrosion Water Chemistry and ISI (IWF) No Not applicable Not applicable to Salem Aging Management Review Results 3-424 Component Group (GALL Report Item No.) Aging Effect/ Mechanism AMP in GALL Report Further Evaluation in GALL Report AMP in LRA, Supplements , or Amendments Staff Evaluation Groups B2 and B4:  galvanized steel, aluminum, stainless steel support members; welds; bolted connections; support anchorage to building structure (3.5.1-50) Loss of material due to pitting and crevice corrosion Structures Monitoring No Structures Monitoring Program; ASME Section XI, SubSection IWF; Periodic Inspection; RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants; Aboveground Non-Steel Tanks; and Bolting Integrity Consistent with the GALL Report (see SER Section 3.5.2.1.2 and 3.5.2.1.5)
Group B1.1:  high-strength, low-alloy bolts (3.5.1-51) Cracking due to SCC and loss of material due to general corrosion Bolting Integrity No ASME Section XI, SubSection IWF Consistent with the GALL Report (see SER Section 3.5.2.1.5 Groups B2 and B4:  sliding support bearings and sliding support surfaces (3.5.1-52) Loss of mechanical function due to corrosion, distortion, dirt, overload, and fatigue due to vibratory and cyclic thermal loads Structures Monitoring No ASME Section XI, SubSection IWF Consistent with the GALL Report (see SER Section 3.5.2.1.6)
Groups B1.1, B1.2, and B1.3:  support members:  welds; bolted connections; support anchorage to building structure (3.5.1-53) Loss of material due to general and pitting corrosion ISI (IWF) No ASME Section XI, SubSection IWF Consistent with the GALL Report Groups B1.1, B1.2, and B1.3:  constant and variable load spring hangers; guides; stops (3.5.1-54) Loss of mechanical function due to corrosion, distortion, dirt, overload, and fatigue due to vibratory and cyclic thermal loa ds ISI (IWF) No ASME Section XI, SubSection IWF Consistent with the GALL Report
 
Aging Management Review Results 3-425 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, galvanized steel, and aluminum support members; welds; bolted connections; support anchorage to building structure (3.5.1-55) Loss of material due to boric acid corrosion Boric Acid Corrosion No Boric Acid Corrosion Consistent with the GALL Report Groups B1.1, B1.2, and B1.3:  sliding surfaces (3.5.1-56) Loss of mechanical function due to corrosion, distortion, dirt, overload, and fatigue due to vibratory and cyclic thermal loads ISI (IWF) No ASME Section XI, SubSection IWF Consistent with the GALL Report Groups B1.1, B1.2, and B1.3:  vibration isolation elements (3.5.1-57) Reduction or loss of isolation function, radiation hardening, temperature, humidity, and sustained vibratory loading ISI (IWF) No Not applicable Not applicable to Salem (see SER Section 3.5.2.1.1)
Galvanized steel and aluminum support members; welds; bolted connections; support anchorage to building structure exposed to air-indoor uncontrolled (3.5.1-58) None None No None Consistent with the GALL Report Stainless steel support members; welds; bolted connections; support anchorage to building structure (3.5.1-59) None None No None Consistent with the GALL Report The staff's review of the structures and component supports groups followed any one of several approaches. One approach, documented in SER Section 3.5.2.1, 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 3.5.2.2, 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 3.5.2.3, reviewed AMR results for components that the applicant indicated are not Aging Management Review Results 3-426 consistent with, or not addressed in, the GALL Report. The staff's review of AMPs credited to manage or monitor aging effects of the structures and component supports component groups is documented in SER Section 3.0.3. 3.5.2.1  AMR Results That Are Consistent with the GALL Report LRA Section 3.5.2.1 identifies the materials, environments, AERMs, and the following programs that manage aging effects for the structures and structural components and their commodity groups:  10 CFR Part 50, Appendix J  ASME Section XI, SubSection IWE  ASME Section XI, SubSection IWF  Boric Acid Corrosion Buried Non
-Steel Piping Inspection One-Time Inspection Periodic Inspection Protective Coating Monitoring and Maintenance Program  RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Structures Monitoring Program TLAA  Water Chemistry Although not identified directly in LRA Section 3.5.2.1, LRA Table 3.5.1 identifies the following additional programs under the discussion column that manage aging effects for the structures and structural components and their commodity groups for specified conditions:
Aboveground Non
-Steel Tanks Bolting Integrity Fire Protection Masonry Wall Program  Open-Cycle Cooling Water System LRA Tables 3.5.2-1 through 3.5.2
-17 summarize AMRs for the structures and component supports groups and indicate AMRs claimed to be consistent with the GALL Report.
For component groups evaluated in the GALL Report for which the applicant claimed consistency with the report and for which it does not recommend further evaluation, the staff's audit and review determined whether the plant
-specific components of these GALL Report component groups were bounded by the GALL Report evaluation.
The applicant noted for each AMR line item how the information in the tables aligns with the information in the GALL Report. The staff audited those AMRs with Notes A through E indicating how the AMR is consistent with the GALL Report.
No te A indicates that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. The staff reviewed these line items to verify consistency with the GALL Report and validity of the AMR for the site
-specific conditions.
 
Aging Management Review Results 3-427 Note B indicates that the AMR line item is consistent with the GALL Report for component, material, environment, and aging effect. In addition, the AMP takes some exceptions to the GALL Report AMP. The staff reviewed these line items to verify consistency with the GALL Report and verified that the identified exceptions to the GALL Report AMPs have been reviewed and accepted. The staff also determined whether the applicant's AMP was consistent with the GALL Report AMP and whether the AMR was valid for the site
-specific conditions.
Note C indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. This note indicates that the applicant was unable to find a listing of some system components in the 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 reviewed these line items to verify consistency with the GALL Report. The staff also determined whether the AMR line item of the different component was applicable to the component under review and whether the AMR was valid for the site-specific conditions.
Note D indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the GALL Report AMP. The staff reviewed these line items to verify consistency with the GALL Report. The staff verified whether the AMR line item of the different component was applicable to the component under review and whether the identified exceptions to the GALL Report AMPs have been reviewed and accepted. The staff also determined whether the applicant's AMP was consistent with the GALL Report AMP and whether the AMR was valid for the site-specific conditions.
Note E indicates that the AMR line item is consistent with the GALL Report for material, environment, and aging effect, but credits a different AMP. The staff reviewed these line items to verify consistency with the GALL Report. The staff also determined whether the credited AMP would manage the aging effect consistently with the GALL Report AMP and whether the AMR was valid for the site
-specific conditions.
LRA Tables 3.5.2-1, 3.5.2-2, 3.5.2-3, 3.5.2-4, 3.5.2-5, 3.5.2-6, 3.5.2-7, 3.5.2-8, 3.5.2-10, 3.5.2-11, 3.5.2-12, 3.5.2-13, 3.5.2-15, 3.5.2-16, and 3.5.2
-17 were revised as a result of the July 8, 2010 response to RAI B.2.1.9-01. The revision added AMR items in these tables to reference the applicant's Bolting Integrity Program to manage the aging for bolting AMR items. Existing bolting AMR items which reference other AMPs are used in conjunction with the added bolting AMR items to properly manage aging for bolting components. The staff's evaluation of the applicant's Bolting Integrity Program is documented in SER Section 3.0.3.2.2. The staff notes that the Bolting Integrity Program is supplemented by other AMPs including but not limited to the Structures Monitoring, Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems, External Surfaces Monitoring, and Buried Piping Inspection programs. These other AMPs supplement the Bolting Integrity Program by implementing the requirements of the Bolting Integrity Program for pressure
-retaining bolted joints, component support bolting, and structural bolting within the scope of license renewal. The applicant's action revised the LRA to add bolting component items in the tables mentioned above that are consistent with the GALL Report and have designated them as such with generic note B.
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.
 
Aging Management Review Results 3-428 The staff reviewed the LRA to confirm that the applicant (1) provided a brief description of the system, components, materials, and environments; (2) stated that the applicable aging effects were reviewed and evaluated in the GALL Report; and (3) identified those aging effects for the structures and structural components and their commodity groups that are subject to an AMR. On the basis of its audit and review, the staff determines that, for AMRs not requiring further evaluation, as identified in LRA Table 3.5.1, the applicant's references to the GALL Report are acceptable and no further staff review is required, with the exception of the following AMRs that the applicant had identified were consistent with the AMRs of the GALL Report and for which the staff determined were in need of additional clarification and assessment. The staff's evaluations of these AMRs are provided in the subsections that follow.
3.5.2.1.1  AMR Results Identified as Not Applicable In LRA Table 3.5.1, item 3.5.1
-5 addresses loss of material due to general, pitting and crevice corrosion. The applicant stated that the corresponding AMR items in the GALL Report are not applicable because Salem is a PWR and the AMR item in the GALL Report are only applicable to particular components of BWR designs. The staff verified that the stated AMR item in the GALL Report are only applicable to components of BWR designs and are not applicable to the Salem LRA and, therefore, finds the applicant's determination acceptable
. In LRA Table 3.5.1, item 3.5.1
-7 addresses loss of prestress due to relaxation, shrinkage, creep, and elevated temperature. The applicant stated that the corresponding AMR item in the GALL Report are not applicable because Salem is a PWR that incorporates a reinforced concrete containment and the AMR item in the GALL Report are only applicable to particular components of BWR designs that use a steel containment or containment designs that use a post
-tensioning system. The staff verified that the stated AMR item in the GALL Report are only applicable to metallic components of BWR designs or post
-tensioned concrete containments and are not applicable to the Salem LRA and, therefore, finds the applicant's determination acceptable
. In LRA Table 3.5.1, item 3.5.1-8 addresses cumulative fatigue damage.
The applicant stated that the corresponding AMR item in the GALL Report are not applicable because Salem is a PWR and the AMR item in the GALL Report are only applicable to particular components of BWR designs. The staff verified that the stated AMR item in the GALL Report are only applicable to metallic components of BWR designs and are not applicable to the Salem LRA and, therefore, finds the applicant's determination acceptable
. In LRA Table 3.5.1, item 3.5.1-11 addresses cracking due to stress corrosion cracking.
The applicant stated that the corresponding AMR item in the GALL Report are not applicable because Salem is a PWR and the AMR item in the GALL Report are only applicable to particular components of BWR designs. The staff verified that the stated AMR item in the GALL Report are only applicable to metallic components of BWR designs and are not applicable to the Salem LRA and, therefore, finds the applicant's determination acceptable
. In LRA Table 3.5.1, item 3.5.1
-13 addresses cracking due to cyclic loading. The applicant stated that the corresponding AMR item in the GALL Report are not applicable because Salem is a PWR and the AMR item in the GALL Report are only applicable to particular components of BWR designs. The staff verified that the stated AMR item in the GALL Report are only applicable to metallic components of BWR designs and are not applicable to the Salem LRA and, therefore, finds the applicant's determination acceptable
.
Aging Management Review Results 3-429 In LRA Table 3.5.1, item 3.5.1
-19 addresses cracking due to stress corrosion cracking. The applicant stated that the corresponding AMR items in the GALL Report are not applicable because Salem is a PWR and the AMR items in the GALL Report are only applicable to particular components of BWR designs. The staff verified that the stated AMR items in the GALL Report are only applicable to metallic components of BWR designs and are not applicable to the Salem LRA and, therefore, finds the applicant's determination acceptable
. In LRA Table 3.5.1, item 3.5.1
-20 addresses loss of material due to general, pitting, and crevice corrosion. Tthe applicant stated that the corresponding AMR items in the GALL Report are not applicable because Salem is a PWR and the AMR item in the GALL Report are only applicable to particular components of BWR designs. The staff verified that the stated AMR item in the GALL Report are only applicable to metallic components of BWR designs and are not applicable to the Salem LRA and, therefore, finds the applicant's determination acceptable
. In LRA Table 3.5.1, item 3.5.1
-21 addresses fretting or lock up due to mechanical wear.
The applicant stated that the corresponding AMR items in the GALL Report are not applicable because Salem is a PWR and the AMR item in the GALL Report are only applicable to particular components of BWR designs. The staff verified that the stated AMR items in the GALL Report are only applicable to metallic components of BWR designs and are not applicable to the Salem LRA and, therefore, finds the applicant's determination acceptable
. In LRA Table 3.5.1, item 3.5.1
-22 addresses loss of material due to corrosion.
The applicant stated that the corresponding AMR item in the GALL Report are not applicable because Salem is a PWR that incorporates a reinforced concrete containment and the AMR items in the GALL Report are only applicable to particular components of BWR designs that use a steel containment or containment designs that use a post-tensioning system. The staff verified that the stated AMR item in the GALL Report are only applicable to metallic components of BWR designs or post
-tensioned concrete containments and are not applicable to the Salem LRA and, therefore, finds the applicant's determination acceptable
. In LRA Table 3.5.1, item 3.5.1
-38 addresses cracking due to stress corrosion cracking; loss of material due to pitting and crevice corrosion. The applicant stated that the corresponding AMR item in the GALL Report are not applicable because Salem does not have Group 7 and 8 stainless steel tank liners. The staff reviewed the LRA and UFSAR and confirmed that the applicant's LRA does not have any Group 7 and 8 stainless steel tank liners that are applicable for this line item and, therefore, finds the applicant's determination acceptable
. In LRA Table 3.5.1, item 3.5.1
-57 addresses reduction or loss of isolation function due to radiation hardening, temperature, humidity, sustained vibratory loading.
The applicant stated that the corresponding AMR item in the GALL Report are not applicable because the Salem design does not include vibration isolation elements in B1.1, B1.2, and B1.3 component supports. The staff reviewed the LRA and UFSAR and confirmed that the applicant's LRA does not have any vibration isolation elements in B1.1, B1.2, and B1.3 component supports that are applicable for this line item and, therefore, finds the applicant's determination acceptable
. 3.5.2.1.2  Loss of Material Due to Pitting and Crevice Corrosion LRA Table 3.5.1, item 3.5.1
-50 addresses galvanized steel, aluminum, or stainless steel support members, welds, bolted connections, and support anchorage to building structures exposed to an outdoor air environment, which are being managed for loss of material due to pitting and crevice corrosion. The LRA credits the Bolting Integrity Program to manage the aging effect for Aging Management Review Results 3-430 stainless steel bolting in the compressed air system (LRA Table 3.3.2-6). The GALL Report recommends GALL AMP XI.S6, "Structures Monitoring Program," to ensure that these aging effects are adequately managed. The associated AMR line item cites generic note E, which indicat es that the LRA AMR is consistent with GALL Report item for material, environment, and aging effect, but a different AMP is credited.
For those line items associated with generic note E, GALL AMP XI.S6 recommends using visual inspections to manage the aging of these line items. In its review of components associated with item 3.5.1
-50 for which the applicant cited generic note E, the staff noted that the Bolting Integrity Program proposes to manage the aging of galvanized steel bolting through the use of visual inspections.
The staff's evaluation of the applicant's Bolting Integrity Program is documented in SER Section 3.0.3.2.2. The staff noted that the Bolting Integrity Program provides visual examinations that are capable of detecting loss of material in bolted fasteners and includes provisions for appropriate corrective actions if indications of degradation are found. In its review of components associated with item 3.5.1
-50, the staff finds the applicant's proposal to manage aging using the Bolting Integrity Program acceptable because (1) the focus of the program is aging management of bolting components, (2) the program includes visual examinations which have the capability to detect and correct loss of material in galvanized steel bolting if it should occur, and (3) the proposed inspection methods are consistent with the inspection methods in the GALL Report recommended AMP.
Based on a review of the programs identified above, the staff determines that the applicant's proposed programs are acceptable for managing the aging effects in the applicable components. The staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.5.2.1.3  Loss of Preload Due to Self
-Loosening In LRA Tables 3.5.2-1 through 3.5.2
-8, 3.5.2-10 through 3.5.2
-13, 3.5.2-16, and 3.5.2-17, for items that reference Table 3.3-1, item 3.3.1-45, the applicant included a reference to Note E and credited the Structures Monitoring Program for managing this aging effect/mechanism in an indoor air environment for carbon and low
-alloy steel bolting and galvanized steel bolting. The applicant also included plant
-specific Notes 1, 2, or 4 (depending on the table number).
Both plant-specific Notes 1 and 2 state:
Based on industry standards and operating experience[,] age related loss of preload/self
-loosening of structural bolting could be caused by vibration, flexing of the joint or cyclic shear loads that could occur in any environment. However, these causes are considered in the design of structural connections and eliminated by the initial preload bolt torquing. Thus, loss of preload/self
-loosening of structural bolting is not significant and will not impact structural intended functions. Nevertheless, loss of preload/self
-loosening will be monitored through the Structures Monitoring Program. 
 
Aging Management Review Results 3-431 Plant-specific note 4 states, "[
the] Structures Monitoring Program is the applicable aging management program for this component."  The applicant stated that components have been aligned to this item number based on material, environment, and aging effect.
The staff reviewed the AMR results lines that referenced Note E and plant
-specific Notes 1, 2, or 4. The staff determined, for these items, that the component type, material, environment, and aging effect are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends GALL AMP XI.M18, "Bolting Integrity," the applicant has proposed using the Structures Monitoring Program.
The LRA states that these components have the intended function of structural support and are examined using the Structures Monitoring Program as the primary AMP. The staff's review of the Structures Monitoring Program is documented in SER Section 3.0.3.2.15. The staff finds the applicant's use of the Structures Monitoring Program acceptable because (1) the Structures Monitoring Program monitors exposed surfaces of bolting for loss of material due to corrosion, loose nuts, missing bolts, or other indications of loss of preload and (2) the program incorporates procedures based on EPRI TR
-104213, "Bolted Joint Maintenance and Applications Guide," to ensure proper specification of bolting material, lubricant, and installation torque. Since the applicant has committed to an appropriate AMP for the period of extended operation, the staff finds that the applicant addressed the AERM adequately.
In LRA Table 3.5.2-2, for items that reference Table 3.3-1, item 3.3.1
-45, the applicant included a reference to Note E and credited the ASME Section XI, SubSection IWF Program for managing this aging effect/mechanism in an indoor air environment for carbon and low
-alloy steel bolting. The applicant stated that components have been aligned to this item number based on material, environment, and aging effect.
The staff reviewed the AMR results lines that referenced Note E and plant
-specific Notes 1 and 2. The staff determined, for these items, that the component type, material, environment, and aging effect are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends AMP XI.M18, "Bolting Integrity," the applicant has proposed using the ASME Section XI, SubSection IWF Program.
The LRA states that these components have the intended function of structural support and are examined using the ASME Section XI, SubSection IWF Program as the primary AMP. The staff's review of the ASME Section XI, SubSection IWF Program is documented in SER Section 3.0.3.1.17. The staff finds the applicant's use of the ASME Section XI, SubSection IWF Program acceptable because (1) the ASME Section XI, SubSection IWF Program provides periodic visual inspections of ASME Class 1, 2, and 3 piping and component support members for loss of material and loss of mechanical function, including inspection of bolting for loss of material and for loss of preload by inspecting for missing, detached, or loosened bolts and nuts, and (2) the program relies on design change procedures that are based on EPRI TR
-104213 guidance to ensure proper specification of bolting material, lubricant, and installation torque. Since the applicant has committed to an appropriate AMP for the period of extended operation, the staff finds that the applicant addressed the AERM adequately.
In LRA Table 3.5.2-3, for items that reference Table 3.2-1, item 3.2.1-24, the applicant included a reference to Note E and credited the ASME Section XI, SubSection IWE and 10 CFR Part 50, Appendix J programs for managing this aging effect/mechanism in an indoor air environment for carbon and low
-alloy steel bolting. The applicant also included plant
-specific Note 1 which states, "ASME Section XI, SubSection IWE and 10 CFR Part 50, Appendix J are the applicable Aging Management Review Results 3-432 aging management program for this component."  The applicant stated that components have been aligned to this item number based on material, environment, and aging effect.
The staff reviewed the AMR results lines that referenced Note E and plant
-specific Note
: 1. The staff determined, for these items, that the component type, material, environment, and aging effect are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends GALL AMP XI.M18, "Bolting Integrity," the applicant has proposed using the ASME Section XI, SubSection IWE and 10 CFR Part 50, Appendix J programs.
The LRA states that these components have the intended function of pressure boundary and that the 10 CFR Part 50, Appendix J and ASME Section XI, SubSection IWE programs have been substituted to manage loss of preload due to self
-loosening in steel bolting exposed to indoor air. The staff's evaluations of the applicant's 10 CFR Part 50, Appendix J and ASME Section XI, SubSection IWE programs are documented in SER Sections 3.0.3.1.18 and 3.0.3.2.13, respectively. The staff finds the applicant's use of the 10 CFR Part 50, Appendix J and ASME Section XI, SubSection IWE programs acceptable because:  (1) the 10 CFR Part 50, Appendix J Program provides for detection of age
-related degradation of components comprising the containment pressure boundary, and (2) the ASME Section XI, SubSection IWE Program conducts general and detailed visual examinations and augmented inspections for evidence of aging effects that could affect leak tightness of the containment structure and includes the pressure
-retaining bolting. Since the applicant has committed to an appropriate AMP for the period of extended operation, the staff finds that the applicant addressed the AERM adequately.
Based on a review of the programs identified above, the staff determines that the applicant's proposed programs are acceptable for managing the aging effects in the applicable components. The staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.5.2.1.4  Increased Hardness, Shrinkage, and Loss of Strength Due to Weathering In LRA Tables 3.5.2-1, 3.5.2-3, 3.5.2-5, and 3.5.2
-7, for items that reference Table 3.3-1, item 3.3.1-61, the applicant included a reference to Note E and credited the Structures Monitoring Program for managing this aging effect/mechanism in an indoor or outdoor environment for elastomers. The applicant also included plant
-specific Notes 2, 3, or 4 (depending on the table number) which each state, "[The] Structures Monitoring Program is the applicable aging management program for this component."  The applicant stated that components have been aligned to this item number based on material, environment, and aging effect. The staff reviewed the AMR results lines that referenced Note E and plant
-specific Notes 2, 3, or 4. The staff determined, for these items, that the component type, material, environment, and aging effect are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends GALL AMP XI.M26, "Fire Protection," the applicant has proposed using the Structures Monitoring Program. In the LRA, it states that this line item relates to compressible joints and seals (seismic gap) and provides an intended function of expansion/separation. 
 
Aging Management Review Results 3-433 The LRA states that these components are examined using the Structures Monitoring Program as the primary AMP. The staff's evaluation of the applicant's Structures Monitoring Program is documented in SER Section 3.0.3.2.15. The staff finds the applicant's use of the Structures Monitoring Program acceptable because:  (1) the Structures Monitoring Program has been enhanced to visually inspect elastomers for hardening, shrinkage, and loss of sealing, (2) the intended function of the elastomers is to provide expansion/separation in seismic gaps, and (3) the LRA does not list an intended function of the elastomers as fire barriers. Since the applicant has committed to an appropriate AMP for the period of extended operation, the staff finds that the applicant addressed the AERM adequately.
In LRA Table 3.5.2-13, for items that reference Table 3.3-1, item 3.3.1-61, the applicant included a reference to Note E and credited the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program for managing this aging effect/mechanism in an air
-outdoor environment for elastomers. The applicant also included plant-specific Note 2 which states, "RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants, is the applicable aging management program for this environment and aging effect/mechanism combination for this component."  The LRA states that this line item relates to the ice barrier, marine dock bumper and provides an intended function of shelter/protection in the service water intake system. The applicant stated that components have been aligned to this item number based on material, environment, and aging effect The staff reviewed the AMR results lines that referenced Note E and plant
-specific Note
: 2. The staff determined, for these items, that the component type, material, environment, and aging effect are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends GALL AMP XI.M26, "Fire Protection," the applicant has proposed using the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program.
The LRA states that these components have the intended function of shelter/protection in the form of elastomers for the ice barrier, marine dock bumper and are examined using the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program as the primary AMP. The RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program is implemented through the applicant's Structures Monitoring Program.
The staff's evaluations of the applicant's RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants and the Structures Monitoring programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.2.15, respectively. The staff finds the applicant's use of the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program acceptable because:  (1) the program has been enhanced to visually inspect elastomers for hardening, shrinkage, and loss of strength due to weathering and elastomer degradation; (2) the program is implemented through the Structures Monitoring Program that conducts visual inspections on a frequency not to exceed 5 years; and (3) the LRA does not list an intended function of the elastomers as fire barriers. Since the applicant has committed to an appropriate AMP for the period of extended operation, the staff finds that the applicant addressed the AERM adequately.
In LRA Table 3.5.2-13, for items that reference Table 3.3-1, item 3.3.1-75, the applicant included a reference to Note E and credited the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program for managing this aging effect/mechanism in a water-flowing environment for elastomers. The applicant also included plant-specific Note 2 which states, "RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants, is the applicable aging management program for this Aging Management Review Results 3-434 environment and aging effect/mechanism combination for this component."  The applicant stated that components have been aligned to this item number based on material, environment, and aging effect.
The staff reviewed the AMR results lines that referenced Note E and plant-specific Note
: 2. The staff determined, for these items, that the component type, material, environment, and aging effect are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends GALL AMP XI.M20, "Open
-Cycle Cooling Water System," the applicant has proposed using the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program.
The LRA states that these components associated with the service water intake system have the intended function of shelter/protection in the form of elastomers for the ice barrier, marine dock bumper and are examined using the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program as the primary AMP. The RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program is implemented through the applicant's Structures Monitoring Program. The staff's evaluations of the applicant's RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants and the Structures Monitoring programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.2.15, respectively. The staff finds the applicant's use of the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program acceptable because:  (1) the program has been enhanced to visually inspect elastomers for hardening, shrinkage, and loss of strength due to weathering and elastomer degradation; (2) the program is implemented through the Structures Monitoring Program that conducts visual inspections on a frequency not to exceed 5 years; and (3)
GALL AMP XI.M20 is intended to address aging effects of material loss and fouling due to micro
- and macro-organisms and various corrosion mechanisms.
Since the applicant has committed to an appropriate AMP for the period of extended operation, the staff finds that the applicant addressed the AERM adequately.
Based on a review of the programs identified above, the staff determines that the applicant's proposed programs are acceptable for managing the aging effects in the applicable components. The staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by
 
10 CFR 54.21(a)(3).
3.5.2.1.5  Loss of Material Due to General, Pitting, Crevice, and Microbiologically
-Influenced Corrosion In LRA Table 3.5.2-1, 3.5.2-3, and 3.5.2
-13, for items that reference Table 3.3-1, item 3.3.1-80, the applicant included a reference to Note E and credited the Structures Monitoring Program for managing this aging effect/mechanism for stainless steel material in a raw water environment.
The staff reviewed the AMR results lines that referenced Note E and plant
-specific Notes 1 and 4. The staff determined, for these items, that the material, aging effect, and environment are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends GALL AMP XI.M20, "Open
-Cycle Cooling Water System," the applicant has proposed using the Structures Monitoring Program.
The LRA states that the stainless steel sump screen trench cover, sump liner, liner/liner anchors/integral attachments, or vortex suppressors have intended functions of either structural Aging Management Review Results 3-435 support, water
-retaining boundary, filter, or direct flow and are examined using the Structures Monitoring Program.
The staff's evaluation of the applicant's Structures Monitoring Program is documented in SER Section 3.0.3.2.15.
The staff finds the applicant's use of the Structures Monitoring Program acceptable because the program (1) performs visual inspections to monitor for indications of degradation, (2) implements the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program, and (3) has been enhanced to conduct the visual inspections on a frequency not to exceed 5 years. Since the applicant has committed to an appropriate AMP for the period of extended operation, the staff finds that the applicant addressed the AERM adequately.
In LRA Table 3.5.2-13, for items that reference Table 3.3
-1, item 3.3.1
-80, the applicant included a reference to Note E and credited the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program for managing this aging effect/mechanism in a raw water environment for stainless steel bolting or stainless steel concrete anchors having an intended function of structural support. The applicant also included plant-specific Note 2 which states, "RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants, is an appropriate AMP for environment and aging effect/mechanism combination for this component."
The staff reviewed the AMR results lines that referenced Note E and plant
-specific Note
: 2. The staff determined, for these items, that the material, aging effect, and environment are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends GALL AMP XI.M20, "Open
-Cycle Cooling Water System," the applicant has proposed using the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program. The LRA states that the stainless steel structural bolting and stainless steel concrete anchors have an intended function of structural support and are examined using the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program. The staff's evaluation of the applicant's RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program is documented in SER Section 3.0.3.2.16. The staff finds the applicant's use of the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program acceptable because the program (1) is based on guidance provided in RG 1.127 and ACI 349.3R, (2) performs visual inspections, (3) is implemented through the Structures Monitoring Program to monitor for indications of degradation, and (4) has been enhanced to conduct the visual inspections on a frequency not to exceed 5 years. Since the applicant has committed to an appropriate AMP for the period of extended operation, t he staff finds that the applicant addressed the AERM adequately.
In LRA Table 3.5.2-3, for items that reference Table 3.4-1, item 3.4.1
-33, the applicant included a reference to Note E and credited the Periodic Inspection Program for managing this aging effect/mechanism in a raw water environment for stainless steel material having an intended function of filter. The applicant also included plant
-specific Note 12 which states that periodic Inspection is the applicable aging management program for this component.
The staff reviewed the AMR results lines that referenced Note E and plant
-specific Note
: 12. The staff determined, for these items, that the material, aging effect, and environment are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends GALL AMP XI.M20, "Open
-Cycle Cooling Water System," the applicant has proposed using the Periodic Inspection Program.
 
Aging Management Review Results 3-436 The LRA states that the stainless steel sump screen has an intended function of filter and is examined using the Periodic Inspection Program. The staff's evaluation of the applicant's Periodic Inspection Program is documented in SER Section 3.0.3.3.2. The Periodic Inspection Program is a condition monitoring program that includes provisions for periodic visual inspections of stainless steel components in a raw water environment to detect loss of material and the presence and extent of fouling that could result in reduction of heat transfer. The applicant noted that the inspection frequency is established based on plant and industry operating experience and for stainless steel components subject to a raw water environment, operating experience indicates that a 10
-year inspection frequency will be adequate to detect loss of material prior to loss of component intended function. The staff agrees that the Periodic Inspection Program is an appropriate AMP to address this AERM, however, since the GALL AMP XI.M20 inspections are done annually and during refueling outages, it is unclear to the staff that an inspection interval of 10 years will be adequate to address the AERM. By a June 7, 2010 letter, the staff issued RAI 3.5.2.1-03 to address this issue.
In its July 8, 2010, response the applicant stated that components in the containment structure were aligned to GALL Report item 3.4.1
-33 to show agreement between the LRA and the GALL Report with respect to the identified aging effects and mechanisms for the material and environment combination. The applicant further stated that the alignment was not intended to suggest consistency with the AMP recommended by the GALL Report and that the recommended GALL Report programs are not applicable for aging management of the containment sump screens. The applicant also stated that the sump screens are not located within the sump pit and are not normally exposed to raw water; therefore, raw water is deleted as an environment for the containment sump screens. The applicant further stated that the screens may be exposed to air with untreated steam or water leakage so an AMR line item was included in the original application to address this environment.
The staff reviewed the applicant's response and found it acceptable because it explains that the components are not exposed to a raw water environment and it removes the corresponding AMR line item from the application. The staff's evaluation of aging management of screens in an air with untreated steam or water leakage environment is addressed in SER Section 3.5.2.3.3.
Based on its review of the applicant's response, the staff finds that the applicant addressed the AERM adequately and the staff's concern in RAI 3.5.2.1-03 is resolved.
In LRA Tables 3.2.2-3, 3.3.2-2, and 3.4.2
-1, for items that reference Table 3.5-1, ite m 3.5.1-50, the applicant included a reference to Note E and credited the Aboveground Non
-Steel Tanks Program for managing loss of material due to general, pitting, and crevice corrosion in an air-outdoor environment for stainless steel components.
The staff reviewed the AMR lines that reference Note E. The staff determined, for these items, that the material, aging effect, and environment are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends GALL AMP XI.S6, "Structures Monitoring Program," the applicant has proposed using the Aboveground Non
-Steel Tanks Program. The staff's evaluation of the applicant's Aboveground Non
-Steel Tanks Program is documented in SER Section 3.0.3.3.3. The staff noted that the Aboveground Non
-Steel Tanks Program performs visual inspections to monitor for indications of degradation at a frequency of 5 years or less. GALL AMP XI.S6 recommends visual inspections at a frequency of 5 years or less for components exposed to an exterior environment. The staff finds the applicant's use of the Aboveground Non
-Steel Tanks Program acceptable because the applicant's credited program Aging Management Review Results 3-437 performs inspections which are equivalent to the GALL Report recommended program. The staff finds that the applicant addressed the AERM adequately.
In LRA Table 3.5.2-2, for items that reference Table 3.5-1, item 3.5.1-50, the applicant included a reference to Note E and credited the ASME Section XI, SubSection IWF Program for managing this aging effect/mechanism in an air
-outdoor environment for stainless steel material having an intended function of structural support. The applicant also included plant
-specific Note 1 which states, "ASME Section XI, SubSection IWF is the applicable aging management program for this component."  The applicant stated that components have been aligned to this item number based on material, environment, and aging effect.
The staff reviewed the AMR results lines that referenced Note E and plant
-specific Note
: 1. The staff determined, for these items, that the material, aging effect, and environment are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends GALL AMP XI.S6, "Structures Monitoring Program," the applicant has proposed using the ASME Section XI, SubSection IWF Program.
The LRA states that the stainless steel supports for ASME Class 2 and 3 piping and supports have an intended function of structural support and are examined under the ASME Section XI, SubSection IWF Program. The staff's evaluation of the applicant's ASME Section XI, SubSection IWF Program is documented in SER Section 3.0.3.1.17. The staff finds the applicant's use of the ASME Section XI, SubSection IWF Program acceptable because the program (1) provides periodic visual inspections of ASME Class 1, 2, and 3 piping and component support members for loss of material and loss of mechanical function, including inspection of bolting for loss of material and for loss of preload by inspecting for missing, detached, or loosened bolts and nuts and (2) relies on design change procedures that are based on EPRI TR
-104213 guidance to ensure proper specification of bolting material, lubricant, and installation torque. Since the applicant has committed to an appropriate AMP for the period of extended operation, the staff finds that the applicant addressed the AERM adequately.
In LRA line items that reference Table 3.5-1, item 3.5.1
-50, the applicant included a reference to Note E and credited the Periodic Inspection Program for managing this aging effect/mechanism in an air-outdoor environment for aluminum and stainless steel materials.
The staff reviewed the AMR results lines that referenced Note E. The staff determined, for these items, that the material, aging effect, and environment are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends GALL AMP XI.S6, "Structures Monitoring Program," the applicant has proposed using the Periodic Inspection Program.
The LRA states that the Periodic Inspection Program is a condition monitoring program that manages aging of piping, piping components, piping elements, ducting components, tanks, and heat exchanger components and includes provisions for periodic visual inspections of aluminum components to detect loss of material aging effects. The staff's evaluation of the applicant's Periodic Inspection Program is documented in SER Section 3.0.3.3.2. The LRA also states that the visual inspections are conducted on a 10
-year inspection frequency that has been established based on plant and industry operating experience. The staff notes that the applicant's Periodic Inspection Program does not appear to address the aluminum and stainless steel insulation jacketing and for components located in an air
-outdoor environment, does not meet guidance such as that provided in ACI 349.3R as referenced by GALL AMP XI.S6, which Aging Management Review Results 3-438 recommends an inspection frequency of 5 years for this environment. By a June 7, 2010 letter, the staff issued RAI 3.5.2.1-04 to address this issue.
In its July 8, 2010,  response the applicant stated that the aluminum and stainless steel components were aligned to GALL Report item 3.3.1
-50 to show agreement between the LRA and the GALL Report with respect to the identified aging effects and mechanisms for the material and environment combination; the alignment was not intended to suggest consistency with the AMP recommended by the GALL Report and that the recommended GALL Report programs are not applicable for aging management of the components. The applicant further explained that the Periodic Inspection Program is the appropriate program to manage these components and the program includes all the referenced items within its scope. The applicant explained that the 10
-year inspection frequency is appropriate for stainless steel and aluminum components exposed to outdoor air due to the corrosion resistance of the materials. The applicant explained that this conclusion was supported by plant
-specific operating experience, including inspections of outdoor stainless steel piping in 2002, 2006, and 2008 which showed no signs of age
-related degradation. These inspections suggest little to no age
-related degradation after 30 years in service and suggest that corrosive contamination is not an issue in the Salem air-outdoor environment.
The staff reviewed the applicant's response and noted that all of the AMR line items in question are included within the scope of the applicant's Periodic Inspection Program. The staff also noted that the applicant provided justification for the 10
-year inspection interval, based on plant-specific operating experience. Based on its review, the staff finds the applicant's use of the Periodic Inspection Program acceptable because it includes appropriate visual inspections at an appropriate frequency to detect degradation of aluminum and stainless steel components exposed to an air
-outdoor environment. The staff finds that the applicant addressed the AERM adequately and the staff's concern in RAI 3.5.2.1-3 is resolved.
In LRA Table 3.5.2-13, for items that reference Table 3.5-1, item 3.5.1
-50, the applicant included a reference to Note E and credited the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program for managing this aging effect/mechanism in an air
-outdoor environment for stainless steel bolting and concrete anchors having an intended function of structural support for the service water intake. The applicant also included plant
-specific Note 2 which states, "RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants, is the applicable aging management program for this component."
The staff reviewed the AMR results lines that referenced Note E and plant
-specific Note
: 2. The staff determined, for these items, that the material, aging effect, and environment are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends GALL AMP XI.S6, "Structures Monitoring Program," the applicant has proposed using the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program. The LRA states that the stainless steel bolting and concrete anchors are examined under the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program. The staff's evaluation of the applicant's RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program is documented in SE R Section 3.0.3.2.16. The LRA also states that the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program is implemented through the applicant's Structures Monitoring Program. The staff finds the applicant's use of the RG 1.127, Aging Management Review Results 3-439 Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program acceptable because the program:  (1) is implemented through the Structures Monitoring Program, (2) includes provisions to monitor for indications of degradation, and (3) has been enhanced to conduct visual inspections on a frequency not to exceed 5 years. Since the applicant has committed to an appropriate AMP for the period of extended operation, the staff finds that the applicant addressed the AERM adequatel
: y. In LRA Table 3.5.2-17, for items that reference Table 3.5-1, item 3.5.1
-47, the applicant included a reference to Note E and credited the Structures Monitoring Program for managing this aging effect/mechanism in an air
-outdoor environment for cast iron hatches/plugs (manhole/manhole covers) having an intended function of structural support for the yard structures. The applicant also included plant
-specific Note 3 which states, "Water control structures are monitored in accordance with the Structures Monitoring Program, which includes the ten attributes of NUREG
-1801 Regulatory Guide 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants (XI.S7)."
The staff reviewed the AMR results lines that referenced Note E and plant
-specific Note
: 3. The staff determined, for these items, that the material, aging effect, and environment are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends GALL AMP XI.S7, "RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants," the applicant has proposed using the Structures Monitoring Program. The LRA states that the cast iron hatches/plugs are examined under the Structures Monitoring Program under which the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program is implemented. The staff's evaluations of the applicant's Structures Monitoring Program and RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program are documented in SER Sections 3.0.3.2.15 and 3.0.3.2.16, respectively. Although the GALL Report line item addresses metal (steel) components, cast iron is an alloy of iron having a higher carbon content that makes it more resistant to corrosion than steel. The staff finds the applicant's use of the Structures Monitoring Program acceptable because the program:  (1) implements the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program, (2) performs visual inspections to monitor for indications of degradation, and (3) has been enhanced to conduct the visual inspections on a frequency not to exceed 5 years. Since the applicant has committed to an appropriate AMP for the period of extended operation, the staff finds that the applicant addressed the AERM adequately.
In LRA Table 3.5.2-2, for items that reference Table 3.5-1, item 3.5.1
-51, the applicant included a reference to Note E and credited the ASME Section XI, SubSection IWF Program for managing this aging effect/mechanism in an indoor air environment for high
-strength, low
-alloy steel bolting with a yield strength greater than 150 ksi and having an intended function of structural support for Class 1 piping and components (high
-strength bolting for NS SS component supports). The applicant also included plant
-specific Notes 1, 5, and 6 in LRA Table 3.5.2-2. Plant-specific Note 1 states, "ASME Section XI, SubSection IWF is the applicable aging management program for this component."  Plant
-specific Not e 5 states:
Supports for the Reactor Coolant Pumps and Unit 1 Steam Generators have high strength maraging steel bolts (Vascomax 200, 300) with actual yield strength greater than 150 ksi. The bolts are not preloaded (not torqued) and are not subject to high tensile stress or a corrosive environment. A review of plant Aging Management Review Results 3-440 operating experience has not identified any instances of SCC for the bolts. Therefore, cracking due to stress corrosion cracking is not an aging effect requiring aging management. Loss of material is the only aging effect requiring aging management.
Plant-specific Note 6 states, "Loss of preload/self
-loosening is not applicable because the bolts are not required to be preloaded by design. Also, the bolt nuts are either tack welded or lock wired to prevent undesirable self
-loosening."
The staff reviewed the AMR results lines that referenced Note E and plant
-specific Notes 1, 5, and 6. The staff determined, for these items, that the material, aging effect, and environment are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends GALL AMP XI.M18, "Bolting Integrity," the applicant has proposed using the ASME Section XI, SubSection IWF Program.
The LRA states that these components have the intended function of structural support and are examined using the ASME Section XI, SubSection IWF Program as the primary AMP. The staff's review of the applicant's Section XI, SubSection IWF Program is documented in SER Section 3.0.3.1.17. The staff finds the applicant's use of the ASME Section XI, SubSection IWF Program acceptable because (1) the program performs periodic visual examinations of exposed surfaces of bolting used in supports for loss of material and for loss of preload by inspecting for missing, detached, or loosened bolts and nuts, including monitoring for loss of material due to general corrosion of high
-strength bolts (actual yield strength greater than 150 ksi) used in NSSS component supports; (2) the bolts are in an indoor air
- non-corrosive environment; (3) the bolts are not preloaded and are either tack welded or lock wired to prevent undesirable self-loosening; and (4) the program incorporates procedures based on EPRI TR
-104213, "Bolted Joint Maintenance and Applications Guide," to ensure proper specification of bolting material, lubricant, and installation torque. Since the applicant has committed to an appropriate AMP for the period of extended operation, the staff finds that the applicant addressed the AERM adequately
. Based on a review of the programs identified above, the staff determines that the applicant's proposed programs are acceptable for managing the aging effects in the applicable components. The staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.5.2.1.6  Loss of Mechanical Function Due to Corrosion, Distortion, Dirt, and Overload and Fatigue Due to Vibratory and Cyclic Thermal Loads In LRA Table 3.5.2-2, for items that reference Table 3.5-1, item 3.5.1-52, the applicant included a reference to Note E and credited the ASME Section XI, SubSection IWF Program for managing this aging effect/mechanism in an indoor environment for Graph
-Air tool steel having an intended function of structural support for Class 1 piping and components (sliding surfaces-NSSS component supports). The applicant also included plant-specific Note 1 which states, "ASME Section XI, SubSection IWF is the applicable aging management program for this component."
 
Aging Management Review Results 3-441 The staff reviewed the AMR results lines that referenced Note E and plant
-specific Note
: 1. The staff determined, for these items, that the material, aging effect, and environment are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends GALL AMP XI.S6, "Structures Monitoring Program," the applicant has proposed using the ASME Section XI, SubSection IWF Program.
The LRA states that these components have the intended function of structural support and are examined using the ASME Section XI, SubSection IWF Program as the primary AMP. The staff's review of the applicant's Section XI, SubSection IWF Program is documented in SER Section 3.0.3.1.17. The GALL Report recommends no further evaluation for lockup of sliding surfaces if the Structures Monitoring Program is used to manage aging. In its review, the staff noted that the applicant is not using the Structures Monitoring Program as the AMP and the staff was unable to verify that these sliding support surfaces were being inspected for loss of mechanical function due to corrosion, distortion, dirt, and overload, or fatigue due to vibratory and cyclic thermal loads under the ASME Section XI, SubSection IWF Program. By a June 7, 2010 letter , the staff issued RAI 3.5.2.1-05 to address this issue.
In its response dated July 8, 2010, the applicant stated that the Gra ph-Air tool steel components were aligned to GALL Report item 3.5.1
-52 to show agreement between the LRA and the GALL Report with respect to the identified aging effects and mechanisms for the material and environment combination; however, the ASME Section XI, SubSection IWF Program was credited because the components are ASME Code Section XI Class 1 component supports. The applicant also stated that the ASME Section XI, SubSection IWF Program requires visual examinations to detect loss of mechanical function, regardless of the specific aging mechanism.
The staff reviewed the applicant's response and noted that the scope of the ASME Section XI, SubSection IWF Program includes the Graph
-Air tool steel components, as well as the aging effect of loss of mechanical function. The applicant also explained that the ASME Section XI, SubSection IWF Program was the appropriate AMP because the components are ASME Code Section XI Class 1 supports. Based on its review, the staff finds the applicant's use of the ASME Section XI, SubSection IWF Program acceptable because it includes appropriate visual inspections at an appropriate frequency to detect degradation of sliding supports. The staff finds that the applicant addressed the AERM adequately and the staff's concern in RAI 3.5.2.1-05 is resolved.
Based on a review of the programs identified above, the staff determines that the applicant's proposed programs are acceptable for managing the aging effects in the applicable components. The staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.5.2.1.7  Cracks and Distortion Due to Increased Stress Levels from Settlement In LRA Table 3.5.2-3, for items that reference Table 3.5-1, item 3.5.1
-2, the applicant included a reference to Note E and credited the ASME Section XI, SubSection IWL Program for managing this aging effect/mechanism for reinforced concrete in an air
-outdoor or indoor air environment. The applicant also included plant
-specific Note 5 in LRA Table 3.5.2-3, which states, "ASME Section XI, SubSection IWL is the applicable aging management program for this component." 
 
Aging Management Review Results 3-442 The staff reviewed the AMR results lines that referenced Note E and plant
-specific Note
: 5. The staff determined, for these items, that the material, aging effect, and environment are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends GALL AMP XI.S6, "Structures Monitoring Program," the applicant has proposed using the ASME Section XI, SubSection IWL Program.
The LRA states that these components have intended functions of either flood barrier, missile barrier, pressure boundary, shelter/protection, shielding, or structural support and are monitored by the ASME Section XI, SubSection IWL Program. The staff's review of the applicant's ASME Section XI, SubSection IWL Program is documented in SER Section 3.0.3.1.16. The staff finds the applicant's use of the ASME Section XI, SubSection IWL Program acceptable because (1) the program conducts general visual examinations of accessible surfaces to detect degradation and distress such as defined in ACI 201.1, including loss of material, cracks and distortion, and loss of bond; (2) detailed visual examinations are conducted on concrete surfaces that are suspect to determine the magnitude and extent of deterioration and distress; (3) acceptance criteria are based on ACI 349.3R guidance; and (4) the LRA states that neither a dewatering system nor porous concrete subfoundation exist at Salem. Since the applicant has committed to an appropriate AMP for the period of extended operation, the staff finds that the applicant addressed the AERM adequately.
In LRA Table 3.3.2-12, for items that reference Table 3.5-1, item 3.5.1
-28, the applicant included a reference to Note E and credited the Fire Protection Program for managing this aging effect/mechanism in an outdoor or indoor air environment. The applicant also included plant-specific Note 3 which states, "The Fire Protection aging management program will be used in addition to the Structures Monitoring Program."
The staff reviewed the AMR results lines that reference Note E and plant
-specific Note
: 6. The staff determined, for these items, that the material, aging effect, and environment are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends GALL AMP XI.S6, "Structures Monitoring Program," the applicant has proposed using the Fire Protection Program in addition to the Structures Monitoring Program.
The LRA states that these components have the intended function of fire barriers and are examined using the Structures Monitoring Program in addition to the Fire Protection Program as the AMPs. The staff's evaluations of the applicant's Structures Monitoring and Fire Protection programs are documented in SER Sections 3.0.3.2.15 and 3.0.3.2.5, respectively. The staff finds the applicant's use of the Fire Protection and Structures Monitoring programs acceptable because:  (1) the Fire Protection Program has been enhanced to identify degradation of fire barrier walls, ceilings, and floors for aging effects such as cracking, spalling, and loss of material; and (2) the walls are also inspected under the Structures Monitoring Program, which implements the applicant's Masonry Wall Program. The staff finds that the applicant addressed the AERM adequately
. Based on a review of the programs identified above, the staff determines that the applicant's proposed programs are acceptable for managing the aging effects in the applicable components. The staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
Aging Management Review Results 3-443 3.5.2.1.8  Increase of Porosity and Permeability, Loss of Strength Due to Leaching of Calcium Hydroxide, and Loss of Material Due to Abrasion and Cavitation In LRA Tables 3.3.2-4 and 3.3.2
-23, for items that reference Table 3.5-1, items 3.5.1
-31 and 3.5.1-34, the applicant included a reference to Note E and credited the Buried Non
-Steel Piping Inspection Program for managing these aging effect/mechanisms in a groundwater/soil (external) environment. The applicant also included plant
-specific Note 2 or 10 (depending on the table) which states, "The Buried Non
-Steel Piping Inspection program is substituted to manage the aging effect(s) applicable to this component type, material, and environment combination."
The staff reviewed the AMR results lines that reference Note E. The staff determined, for these items, that the material, aging effect, and environment are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends GALL AMP XI.S6, "Structures Monitoring Program," and GALL AMP XI.S7, "RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants," the applicant has proposed using the Buried Non-Steel Piping Inspection Program.
The LRA states that these reinforced concrete piping and fitting components have the intended function of pressure boundary and are examined using the Buried Non
-Steel Piping Inspection Program. The staff's evaluation of the applicant's Buried Non
-Steel Piping Inspection Program is documented in SER Section 3.0.3.3.4.
Given that there has been a number of recent industry events involving leakage from buried or underground piping, the staff needs further information to evaluate the impact that these recent industry events might have on the applicant's Buried Non-Steel Piping Inspection Program. By a August 6, 2010 letter , the staff issued RAI B.2.1.22 requesting that the applicant provide information regarding how Salem will incorporate the recent industry operating experience into its AMRs and AMPs.
The staff reviewed the RAI response received on September 5, 2010 and sent a follow
-up RAI on October 1 8, 2010 requesting additional information. Pending the applicant's response to, and staff's review of, the aforementioned RAI, the staff is not able to confirm that the Buried Non
-Steel Piping Inspection Program is suitably informed by the recent relevant operating experience.
This is tracked as Open Item OI 3.0.3.2.10
-1. In LRA Table 3.5.2-5, for items that reference Table 3.5-1, items 3.5.1
-37 and 3.5.1
-45, the applicant included a reference to No te E and credited the Structures Monitoring Program for managing this aging effect/mechanism for reinforced concrete in a flowing water environment.
The applicant also included plant
-specific Note 2 in LRA Table 3.5.2-5, which states, "[The] Structures Monitoring Program is the applicable aging management program for this component."
The staff reviewed the AMR results lines that referenced Note E and plant
-specific Note
: 2. The staff determined, for these items, that the material, aging effect, and environment are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends GALL AMP XI.S7, "RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants," or the FERC/U.S. Army Corps of Engineers dam inspections and maintenance programs, the applicant has proposed using the Structures Monitoring Program. The LRA also states that this component is an interior trench constructed of reinforced concrete and has the intended function of directing flow of water. The LRA states that the applicant's Structures Monitoring Program is used to implement the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Aging Management Review Results 3-444 Program. The staff's review of the applicant's Structures Monitoring Program is documented in SER Section 3.0.3.2.15. The staff noted that the component in question is an internal concrete structure, so the Structures Monitoring Program would be the appropriate AMP to address aging of this component. The staff finds the applicant's use of the Structures Monitoring Program acceptable because the program (1) conducts visual inspections on a frequency not to exceed 5 years and (2) is based on guidance provided in RG 1.127 and ACI 349.3R. Since the applicant has committed to an appropriate AMP for the period of extended operation, the staff finds that the applicant addressed the AERM adequately.
In LRA Tables 3.3.2-4 and 3.3.2
-23, for items that reference Table 3.5-1, items 3.5.1
-37 and 3.5.1-45, the applicant included a reference to Note E for both items and credited the Open-Cycle Cooling Water System Program for managing these aging effect/mechanisms in a raw water (internal) environment. The applicant also included plant
-specific Note 3 or 11 (LR A Table 3.3.2-4 and 3.3.2
-23, respectively) which states, "The Open
-Cycle Cooling Water System program is substituted to manage the aging effect(s) applicable to this component type, material, and environment combination."
The staff reviewed the AMR results lines that reference Note E. The staff determined, for these items, that the material, aging effect, and environment are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends GALL AMP XI.S7, "RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants," the applicant has proposed using the Open
-Cycle Cooling Water System Program.
The staff noted that these reinforced concrete piping and fitting components have the intended function of pressure boundary and are examined using the Open
-Cycle Cooling Water System Program. The staff's evaluation of the applicant's Open
-Cycle Cooling Water System Program is documented in SER Section 3.0.3.1.9. The staff also noted that the applicant's O pen-Cycle Cooling Water System Program includes activities to manage internal degradation of piping, including cracking, loss of material, and increase in porosity and permeability. In addition, the concrete piping within scope of this program has a polymer coating applied to the interior surface of the pipe and the interior of each piping header is visually inspected every other refueling outage for signs of coating and concrete degradation. Visual inspections of the piping header will detect indications of age-related degradation in the piping, and the header condition should be representative of the main piping. The type and frequency of the inspections are appropriate based on guidance provided by other GALL Report programs which manage aging of concrete, such as the Structures Monitoring Program. These programs suggest visual inspections with a frequency of at least every 5 years to detect degradation of concrete exposed to raw water. Based on its review, the staff finds that the applicant addressed the AERM adequately.
Based on a review of the programs identified above, the staff determines that the applicant's proposed programs are acceptable for managing the aging effects in the applicable components. The staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
Aging Management Review Results 3-445 3.5.2.1.9  Cracking, Loss of Bond, and Loss of Material (Spalling, Scaling) Due to Corrosion of Embedded Steel and Loss of Material (Spalling, Scaling) and Cracking Due to Freeze
-Thaw In LRA Table 3.3.2-12, for items that reference Table 3.5-1, item 3.5.1
-23 or 3.5.1
-26, the applicant included a reference to Note E and credited the Fire Protection Program for managing this aging effect/mechanism in an air
-outdoor or indoor air environment. The applicant also included plant
-specific Note 3 which states, "The Fire Protection aging management program will be used in addition to the Structures Monitoring Program."
The staff reviewed the AMR results lines that reference Note E and plant
-specific Note 3 in LRA Table 3.3.2-12. The staff determined, for these items, that the material, aging effect, and environment are consistent with the corresponding line of the GALL Report; however, where the GALL Report recommends GALL AMP XI.S6, "Structures Monitoring Program," the applicant has proposed using the Fire Protection Program in addition to the Structures Monitoring Program. The LRA states that these components have the intended function of fire barriers and are examined using the Structures Monitoring Program in addition to the Fire Protection Program as the AMPs. The staff's evaluations of the applicant's Structures Monitoring and Fire Protection programs are documented in SER Sections 3.0.3.2.15 and 3.0.3.2.5, respectively. The staff finds the applicant's use of the Fire Protection and Structures Monitoring programs acceptable becau se (1) the Fire Protection Program has been enhanced to identify degradation of fire barrier walls, ceilings, and floors for aging effects such as cracking, spalling, and loss of material and (2) the walls are also inspected under the Structures Monitoring Program, which implements the Masonry Wall Program. The staff finds that the applicant addressed the AERM adequately.
Based on a review of the programs identified above, the staff determines that the applicant's proposed programs are acceptable for managing the aging effects in the applicable components. The staff concludes that the applicant has demonstrated that the effects of aging for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.5.2.1.10 Conclusion for AMRs Consistent with the GALL Report The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing the associated aging effects. On the basis of its review, the staff concludes that the AMR results, which the applicant claimed to be consistent with the GAL L Report, are consistent with the GALL Report AMRs. Therefore, the staff concludes that the applicant has demonstrated that the aging effects for these components will be adequately managed so that their intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
Aging Management Review Results 3-446 3.5.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation Is Recommended In LRA Section 3.5.2, the applicant further evaluated aging management, as recommended by the GALL Report, for the containments, structures, and component supports components and provides information concerning how it will manage aging effects in the following three areas:
  (1) PWR containments:
aging of inaccessible concrete areas cracks and distortion due to increased stress levels from settlement and reduction of foundation strength, cracking, and differential settlement due to erosion of porous concrete subfoundations if not covered by the Structures Monitoring Program reduction of strength and modulus of concrete structures due to elevated temperature loss of material due to general, pitting, and crevice corrosion loss of prestress due to relaxation, shrinkage, creep, and elevated
 
temperature  cumulative fatigue damage cracking due to SCC cracking due to cyclic loading loss of material (scaling, cracking, and spalling) due to freeze
-thaw  cracking due to expansion and reaction with aggregates and increase in porosity and permeability due to leaching of calcium hydroxide (2) safety-related and other structures and component supports:
aging of structures not covered by the Structures Monitoring Program aging management of inaccessible areas (below
-grade inaccessible concrete areas of Groups 1
-5 and 7-9 structures) reduction of strength and modulus of concrete structures due to elevated temperature for Groups 1
-5 structures aging management of inaccessible areas for Group 6 structures (below-grade inaccessible concrete areas)
Aging Management Review Results 3-447  cracking due to SCC and loss of material due to pitting and crevice corrosion for Groups 7 and 8 stainless steel tank liners aging of supports not covered by the Structures Monitoring Program cumulative fatigue damage due to cyclic loading (3) 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 reviewed the applicant's evaluation to determine whether it adequately addressed the issues further evaluated. In addition, the staff reviewed the applicant's further evaluations against the criteria contained in SRP
-LR Section 3.5.2.2. The staff's review of the applicant's further evaluation follows.
3.5.2.2.1  Pressurized Water Reactor and Boiling Water Reactor Containments The staff reviewed LRA Section 3.5.2.2.1 against the criteria in SRP
-LR Section 3.5.2.2.1. Aging of Inaccessible Concrete Areas. LRA Section 3.5.2.2.1.1 addresses aging of inaccessible concrete areas. In the LRA, the applicant stated that the ASME Section XI, SubSection IWL Program and the Structures Monitoring Program will be used to manage aging of accessible and inaccessible containment structure concrete elements, respectively, for increase in porosity and permeability, cracking, and loss of material (spalling, scaling) due to aggressive chemical attack and cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel. In the LRA, the applicant stated that (1) the containment structure was designed in accordance with ACI 318
-63 and constructed in accordance with ACI 301-66; (2) the Type II Portland cement conformed to ASTM C
-150; (3) fly ash was used in the concrete mixtures; and (4) concrete aggregates conformed to the requirements of ASTM C 33-66 and were tested in accordance with ASTM Specifications C29
-60, C40-66, C127-59, C128-59, and C88-63 and ASTM Specification C289
-65 for potential reactivity. The applicant also stated that a review of operating experience has not indicated any signs of distress due to aggressive chemical attack or corrosion of embedded steel of submerged concrete components, although the chloride levels on the site are considered aggressive (greater than 500 ppm).
The staff reviewed LRA Section 3.5.2.2.1.1 against the criteria in SRP
-LR Section 3.5.2.2.1.1, which states that increase in porosity and permeability, cracking, and loss of material (spalling, scaling) due to aggressive chemical attack and cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel could occur in inaccessible areas of PWR and BWR concrete and steel containments. The GALL Report identifies GALL AMP XI.S2, "ASME Section XI, SubSection IWL," to manage these aging effects and recommends further evaluation of plant
-specific programs to manage these aging effects for inaccessible areas if the environment is aggressive. The staff confirmed that aging management of all accessible areas of the concrete containment building for cracking, loss of material, and increase in porosity and permeability is managed by the ASME Section XI, SubSection IWL Program. The staff's evaluation of the ASME Section XI, SubSection IWL Program is documented in SER Section 3.0.3.1.16. SER Section 3.5.2.2.2, "Aging Management of Inaccessible Areas," documents the staff's review of the applicant's Aging Management Review Results 3-448 evaluation of aging management of inaccessible areas, including the containment
-related concrete. Cracks and Distortion Due to Increased Stress Levels from Settlement and Reduction of Foundation Strength, Cracking, and Differential Settlement Due to Erosion of Porous Concrete Subfoundations, if Not Covered by the Structures Monitoring Program. LRA Section 3.5.2.2.1.2 addresses cracks and distortion due to increased stress levels from settlement and reduction of foundation strength, cracking, and differential settlement due to erosion of porous concrete subfoundations, if not covered by the Structures Monitoring Program. In the LRA, the applicant stated that settlement measurements were made throughout plant construction and during initial operation and indicated a maximum settlement of approximately 12.7 millimeters (0.5 inches) and that this item is not applicable because the concrete components are evaluated under the Structures Monitoring Program and no permanent dewatering system or porous concrete foundations exist at Salem.
The staff reviewed LRA Section 3.5.2.2.1.2 against the criteria in SRP
-LR Section 3.5.2.2.1.2, which states that cracks and distortion due to increased stress levels from settlement and reduction in foundation strength, cracking, and differential settlement due to erosion of porous concrete subfoundations could occur. The GALL Report identifies GALL AMP XI.S6, "Structures Monitoring Program," to manage these aging effects and no further evaluation is recommended if this activity is within scope of the Structures Monitoring Program. The staff confirmed that structures and structural components at Salem are inspected under the Structures Monitoring Program for indications of deterioration such as defined in ACI 201.1R and that the program has been enhanced to include additional acceptance criteria specified in ACI 349.3R
-96, which would capture degradation due to differential settlement. The staff's evaluation of the applicant's Structures Monitoring Program is documented in SER Section 3.0.3.2.15. The staff also confirmed that no permanent dewatering system or porous concrete foundations exist at Salem. The staff finds the applicant's evaluation of this AERM acceptable in that the criteria in SRP
-LR Section 3.5.2.2.1.2 are met.
Reduction of Strength and Modulus of Concrete Structures Due to Elevated Temperature
. LRA Section 3.5.2.2.1.3 addresses reduction of strength and modulus of concrete structures due to elevated temperature. In the LRA, the applicant stated that this item number is not applicable at Salem. The containment structure concrete is not exposed to general temperatures greater than 150 &deg;F or local area temperature greater than 200
&deg;F. Salem TS 3
/4.6.1.5 limits the average air temperature inside the containment during normal plant operation to 120
&deg;F. The bulk air temperature is maintained within the TS limits by recirculating air through cooling coils. High temperature process piping penetrations in the containment wall are insulated and provided with a cooling system to limit concrete temperature to a maximum of 150
&deg;F. No portion of the concrete containment components exceeds the specified temperature limits.
The staff reviewed LRA Section 3.5.2.2.1.3 against the criteria in SRP
-LR Section 3.5.2.2.1.3, which recommends further evaluation of the plant
-specific AMP if any portion of the concrete containment components exceeds the specified temperature limits of 150 &deg;F general and 200 &deg;F local. The staff finds the applicant's evaluation acceptable that this aging effect is not applicable because Salem containment concrete remains below the GALL Report specified temperature limits. SER Section 3.5.2.2.2, "Reduction of Strength and Modulus of Concrete Structures due to Elevated Temperature," documents the staff's review of the applicant's evaluation of aging Aging Management Review Results 3-449 management for reduction of strength and modulus of other in
-scope concrete structures due to elevated temperature.
Loss of Material Due to General, Pitting, and Crevice Corrosion. LRA Section 3.5.2.2.1.4 addresses loss of material due to general, pitting, and crevice corrosion for steel elements of accessible and inaccessible areas of containments. In the LRA, the applicant stated that the ASME Section XI, SubSection IWE and 10 CFR Part 50, Appendix J programs will be used to manage aging of accessible and inaccessible areas of the containment structure steel elements due to general, pitting, and crevice corrosion. The applicant further stated that visual and UT examinations of the containment liner conducted in accordance with ASME Code Section XI, SubSection IWE have not identified significant loss of material due to corrosion. Also, the conditions established in the GALL Report are met and thus, a further evaluation of plant-specific AMPs is not required for managing loss of material due corrosion in inaccessible areas of the containment structure steel elements. The concrete in accessible interior areas of the containment structure is monitored by the Structures Monitoring Program to ensure penetrating cracks that could provide a path for water seepage to the surface of the containment liner, if identified, are entered into the corrective action program and accepted by evaluation or repaired. The applicant also explained that the lower portion of the containment steel liner is largely covered by the liner insulation and stainless steel lagging, causing portions of the liner to be considered inaccessible in accordance with ASME Code Section XI, SubSection IWE-1232. Thus, only the portions of the steel liner that are accessible are inspected by general visual examination in accordance with ASME Code Section XI, SubSection IWE. In the LRA, the applicant explained that the inaccessible steel liner areas are accepted based on the condition of adjacent accessible areas. The applicant also explained that visual inspection of 100 percent of the moisture barrier, at the junction between the containment concrete floor and the containment liner, will be performed in accordance with ASME Code Section XI, SubSection IWE program requirements, to the extent practical, within the limitation of design, geometry, and materials of construction of the components. The bottom edge of the stainless steel insulation lagging will be trimmed, if necessary, to perform the moisture barrier inspections. The applicant further stated that borated water leakage is monitored in accordance with the Boric Acid Corrosion Program. In the LRA, the applicant stated that inspections conducted in accordance with ASME Code Section XI, SubSection IWE and testing in accordance with 10 CFR Part 50, Appendix J will provide reasonable assurance that loss of material due to corrosion in accessible and inaccessible areas of the containment structure will be detected prior to a loss of intended function.
The staff reviewed LRA Section 3.5.2.2.1.4 against the criteria in SRP
-LR Section 3.5.2.2.1.4, which states that loss of material due to general, pitting, and crevice corrosion could occur in steel elements of accessible and inaccessible areas for all types of PWR and BWR containments. The existing program relies on ASME Code Section XI, SubSection IWE and 10 CFR Part 50, Appendix J to manage this aging effect. The GALL Report recommends further evaluation of plant
-specific programs to manage this aging effect for inaccessible areas if corrosion is significant. GALL Report item II.A1
-11 states that for inaccessible areas (embedded steel shell or liner), loss of material due to corrosion is not significant if the following four conditions are satisfied:
  (1) Concrete meeting the specifications of ACI 318 or 349 and the guidance of ACI 201.2R was used for the containment concrete in contact with the embedded containment shell or liner.
Aging Management Review Results 3-450  (2) The concrete is monitored to ensure that it is free of penetrating cracks that provide a path for water seepage to the surface of the containment shell or liner.
  (3) The moisture barrier, at the junction where the shell or liner becomes embedded, is subject to aging management activities in accordance with ASME Code Section XI, SubSection IWE requirements.
  (4) Water ponding on the containment concrete floor is not common and when detected is cleaned up in a timely manner.
The staff's evaluations of the applicant's Structures Monitoring Program; ASME Secti on XI, SubSection IWE Program; and 10 CFR Part 50, Appendix J Program are documented in SER Sections 3.0.3.2.15, 3.0.3.2.13, and 3.0.3.1.18, respectively. The staff found that conditions two, three, and four were adequately addressed; however, the LRA did not discuss condition one adequately in that it was not specified how guidance contained in ACI 201.2R as specified in GALL Report item II.A1
-11 was met. By a June 7, 2010 letter , the staff issued RAI 3.5.2.2.1-01 requesting that the applicant discuss how the concrete in contact with the embedded steel liner complies with the guidance in ACI 201.2R. In its July 8, 2010, response the applicant stated that containment concrete meets the guidance in ACI 201.2R related to low permeability concrete and limiting chlorides in the concrete mix. The applicant explained that the concrete mix design provided for low permeability concrete and included fly ash, while the chlorides were limited in the concrete mix and the mixing water. The applicant further stated that UT results have not identified any corrosion of the containment liner on the concrete side and operating experience has not identified significant signs of distress due to corrosion of embedded steel.
The staff reviewed the applicant's response and noted that it explained that the containment concrete met the guidance in ACI 201.2R in regards to a low permeability concrete and minimum chlorides. Permeability and chloride content are two of the primary factors regarding the ability of concrete to protect embedded steel. Concrete with low permeability and low chloride content provides maximum protection to embedded steel. Based on its review, the staff finds the applicant's response acceptable because it explains that Salem containment concrete meets the guidance in ACI 201.2R for low permeability concrete with low chlorides. The staff finds that the applicant addressed the AERM adequately and the staff's concern in RAI 3.5.2.2.1-01 is resolved.
During the staff's review of operating experience for the ASME Section XI, SubSection IWE and Structures Monitoring programs, it was noted that degradation has been identified on accessible portions of the containment liner near the moisture barrier. Indications of borated water contacting the liner have also been noted sporadically during past outages. To address this, the staff issued several RAIs requesting that the applicant explain how aging would be managed. The staff's review and resolution of these issues, including the RAIs, can be found in the ASME Section XI, SubSection IWE Program and Structures Monitoring Program evaluations documented in SER Sections 3.0.3.2.13 and 3.0.3.2.15, respectively.
On the basis of its review, the staff finds the applicant's evaluation of the AERM acceptable. The applicant has either demonstrated why corrosion is insignificant or committed to additional inspections for areas where corrosion may be significant (see SER Sections 3.0.3.2.13 and 3.0.3.2.15). 
 
Aging Management Review Results 3-451 Loss of Prestress Due to Relaxation, Shrinkage, Creep, and Elevated Temperature. LRA Section 3.5.2.2.1.5 addresses loss of prestress due to relaxation, shrinkage, creep, and elevated temperature. In the LRA, the applicant stated that loss of prestress forces due to relaxation, shrinkage, creep, and elevated temperature for the Salem containment structure is not applicable since the Salem containment structure does not use a prestressed concrete containment design.
The staff finds the applicant's evaluation acceptable that this aging effect is not applicable on the basis that the Salem containment is a reinforced concrete containment with no
 
post-tensioned concrete.
Cumulative Fatigue Damage. LRA Section 3.5.2.2.1.6 addresses cumulative fatigue damage. In the LRA, the applicant stated that a TLAA evaluation for the transfer tube bellows was performed. The stainless steel transfer tube bellows are not part of the containment penetration bellows and are not part of the containment pressure boundary, but are a water
-retaining boundary associated with the reactor cavity in the containment and the transfer pool in the fuel handling building. The applicant further stated that the TLAA evaluation shows that the projected number of cycles for 60 years is less than the design cycles.
Thus, cracking of transfer tube bellows due to cyclic loading is not expected to occur through the period of extended operation. The applicant also stated that the TLAA is evaluated in accordance with 10 CFR 54.21(c) and evaluation of the TLAA is discussed in Section 4.5, "Fuel Transfer Tube Bellows Design Cycles."  Cumulative fatigue damage and associated TLAA evaluations are only applicable to the stainless steel transfer tube bellows. The applicant explained that a fatigue analysis is not included in the CLB for containment penetrations (including penetration sleeves and dissimilar metal welds) and that cracking of the containment penetration bellows due to cyclic loading is not applicable because the containment penetration bellows located outside of the containment are not within the scope of license renewal and are not part of the containment leakage limiting boundary per UFSAR Section 3.8.1.6.8.10, "Piping Penetrations."
The staff reviewed LRA Section 3.5.2.2.1.6 against the criteria in SRP
-LR Secti on 3.5.2.2.1.6, which states that fatigue analyses of penetrations are TLAAs as defined in 10 CFR 54.3. The evaluation of this TLAA is addressed separately in SER Section 4.6. The staff confirmed that there are no containment penetration bellows within the scope of license renewal at Salem. The staff's review of the applicant's evaluation of the remaining TLAAs can be found in SER Section 4.6. Cracking Due to Stress
-Corrosion Cracking. LRA Section 3.5.2.2.1.7 refers to Table 3.5.1, item 3.5.1-10 and addresses SCC of containment structures. The LRA states that item 3.5.1
-11 is not applicable because it is only applicable to BWRs. The LRA, under item 3.5.1-10, indicates that SCC is not an applicable aging mechanism for the carbon steel penetration sleeves, stainless steel penetration bellows, and dissimilar metal welds. The LRA further indicates that the material of the containment liner and associated penetration sleeves is carbon steel and the high temperature piping systems penetrating the containment are generally made out of carbon steel. The LRA states that there are stainless steel and dissimilar metal welds associated with stainless steel piping welded to penetration sleeve cap plates.
The LRA states that SCC is only applicable to stainless steel under specific conditions, which include concentrations of chloride or sulfate contaminants, high stress, and temperatures greater than 60
&deg;C (140 &deg;F). The LRA also states that the containment pressure boundary welds between stainless steel piping and penetration sleeves, with normal operating Aging Management Review Results 3-452 temperatures above 140
&deg;F, are not highly stressed. LRA Section 3.5.2.2.1.7 further states that cracking of the containment stainless steel penetration bellows, due to SCC, is not applicable because the containment penetration bellows are not part of the containment leakage limiting boundary. LRA Section 3.5.2.2.1.6 also indicates that the containment penetration bellows located outside of the containment are not within the scope of license renewal.
The staff reviewed LRA Section 3.5.2.2.1.7 against the criteria in SRP
-LR Section 3.5.2.2.1.7, which states that cracking due to SCC of stainless steel penetration sleeves, penetration bellows, and dissimilar metal welds could occur in all types of PWR and BWR containments. The SRP-LR further states that cracking due to SCC could also occur in stainless steel vent line bellows for BWR containments. The staff noted that the GALL Report, under item II.A3
-2, indicates that this aging issue should be managed by the ASME Section XI, SubSection IWE Program and 10 CFR Part 50, Appendix J Program. Furthermore, the GALL Report indicates that transgranular SCC is a concern for dissimilar metal welds and that for the period of extended operation, Examination Categories E
-B and E-F and additional appropriate examinations to detect SCC in bellows assemblies and dissimilar metal welds are warranted.
In its review, the staff noted that LRA Table 3.5.1, item 3.5.1
-10 states that SCC will not occur at the penetration sleeves, penetration bellows, and associated welds within the scope of license renewal because the normal stress and environmental exposure conditions are not conducive to the development of SCC. However, LRA Table 3.5.2-3 (page 3.5-179) addresses loss of material due to pitting and crevice corrosion in the stainless steel penetration sleeves (cap plates) exposed to air with steam or water leakage. The applicant credited the 10 CFR Part 50, Appendix J Program and the ASME Section XI, SubSection IWE Program to manage loss of material for the components. LRA Note 3 (page 3.5-187) also states that air with steam or water leakage environment is applicable to local areas inside the containment that are exposed to potential service water leakage or spray. In addition, LRA Note 3 states that plant operating experience showed that metal components in this environment exhibit aging effects observed in an air-outdoor environment. Therefore, the staff noted that the AMR results of the applicant are in potential conflict with the applicant's claim that the normal environmental conditions are not conducive to the development of SCC.
LRA Section 3.5.2.2.1.7 further states that the containment pressure boundary welds between stainless steel piping and penetration sleeves, with normal operating temperatures above 60
&deg;C (140 &deg;F), are not highly stressed. However, the LRA does not provide a detailed technical basis for the applicant's claim that the penetration sleeves are not highly stressed so that the normal stress conditions are not conducive to the development of SCC.
By a June 17, 2010 letter , the staff issued RAI 3.5.2.2.1.7
-01 requesting that applicant:  (1) describe detailed operating experience in terms of the observation of pitting and crevic e corrosion and SCC in the penetrations (penetration sleeves, bellows, and welds) and determine whether the operating experience supports the applicant's claim that the normal stress and environmental exposure conditions are not conducive to the development of SCC in these components, (2) clarify why the applicant claims that the environmental condition is not conducive to the development of SCC in the containment penetrations taking into account the "air with steam or water leakage" environment, (3) describe how the applicant determined that the welds between the stainless steel piping and penetration sleeves are not highly stressed and clarify whether the stress evaluation includes residual stresses and whether the condition including residual stresses is not conducive to the development of SCC in the containment penetrations, and (4) based on the information provided for the aforementioned requests, justify why SCC is not applicable to the stainless steel penetrations.
 
Aging Management Review Results 3-453 In its July 15, 2010, response the applicant stated that the hot pipe penetrations were installed with stainless steel expansion bellows on the outside of the containment and the bellows are not part of the pressure boundary. The applicant further indicated that the cold pipe penetrations have no expansion bellows. In addition, the applicant stated that in both cases, the containment pressure boundary is formed by the penetration sleeve, cap plates, piping, and the associated welds inside the containment. The applicant stated that the pipe penetration sleeves are constructed of carbon steel, while the cap plates are stainless steel or carbon steel. The applicant also stated that the containment penetration boundary welds of interest are the cap plate to penetration sleeve for those cap plates constructed of stainless steel (dissimilar metal welds) and the cap plate to penetrating pipe, for penetrating pipe constructed of stainless steel. In addition, the applicant stated that penetration sleeves and the cap plates inside the containment are exposed to a normal operating PWR containment atmosphere environment and that the "air with steam or water leakage" environment was conservatively assumed for penetration sleeves and cap plates where leakage has occurred from brackish water systems.
In its July 15, 2010 response
, which addresses the operating experience review, the applicant stated that a search of all available data in the corrective action database was performed for operating experience related to the penetration pressure boundary welds of interest and that there were no items associated with pitting, crevice corrosion, or SCC of the stainless steel containment penetration pressure boundary components or welds. The applicant also stated that this operating experience supports the position that normal stress and environmental exposure conditions are not conducive to the development of SCC.
In its July 15, 2010 response, which addresses the evaluation of environmental conditions, the applicant stated that operating experience reviews revealed that both Salem Units 1 and 2 have previously experienced containment fan cooling Unit leaks in the containment. The applicant also stated that these previous event driven leaks have introduced a potential for the containment penetration pressure boundary stainless steel and dissimilar metal welds to be exposed to brackish water leakage. The applicant further stated that the elevations in the containment are separated for the most part by solid floors, but there are gaps between the floors and the containment wall that introduces a potential pathway to the containment penetrations located on the lower elevations. In addition, the applicant stated that corrective actions taken as a result of the past leaks included modifications which were implemented in 2008 at both units that substantially reduced the probability of water hammer events, which were the cause of the majority of the previous leaks.
The applicant also stated that as a result of the events and site sensitivity to the potential adverse effects of the service water leakage, a comprehensive event driven service water spill response procedure was developed to mitigate any possible similar events in the future. The applicant indicated that the applicant's procedure includes requirements for walkdowns, swipe sampling for chlorides, flushing, cleaning with demineralized water, and re
-swiping to assure residual chloride levels are below an acceptable level. The applicant further stated that since there was a potential for an adverse environment at the penetrations in the past, it cannot be concluded that the environmental conditions conducive to the development of SCC were never present. Additionally, the applicant indicated that the operating experience reviews, liquid penetrant surface examinations, and the Appendix J Type "A" tests associated with the stainless steel and dissimilar metal containment penetration pressure boundary welds have not revealed any indications of SCC.
In its July 15, 2010 response, which addresses the stress evaluation, the applicant indicated that it reviewed the calculations that verified the adequacy of the design for the piping Aging Management Review Results 3-454 penetrations. The applicant also indicated that in the calculations, the stresses on the penetrations and associated welds are low when compared to the allowable stresses. The applicant further indicated that residual weld stresses were not included in the evaluation that concluded the piping and penetration sleeves are not highly stressed. Additionally, the applicant indicated that since the threshold for the minimum level of tensile stress necessary for SCC to occur cannot be quantified and is also dependent on the relative severity of the corrosion-affecting parameters and other factors, it cannot be concluded with absolute certainty that the residual stresses present are not conducive to the development of SCC for the components.
In its July 15, 2010 response, which addresses the applicability of SCC to the stainless steel containment penetrations and associated welds, the applicant indicated that operating experience reviews, including the results of the ASME Code Section XI, SubSection IWE inspections, liquid penetrant surface examinations, and Appendix J Type "A" tests, have not revealed any indications of SCC in the dissimilar metal welds associated with the cap plates. The applicant also stated, however, that based on the information provided above, it has been concluded there is a potential for SCC of the stainless steel and dissimilar metal welds associated with the containment penetration cap plate pressure boundary welds that are subject to normal operating temperatures greater than 1 40 &deg;F. The applicant further indicated that cracking due to SCC is considered potentially applicable for the penetration sleeve (cap plate) components that involve stainless steel material with normal operating temperatures greater than 140 &deg;F exposed to an air with steam or water leakage environment in the containment structure.
In its July 15, 2010 response, the applicant also revised LRA Sections 3.5.2.2.1.7, A.2.1.28, A.2.1.31, B.2.1.28, and B.2.1.31 and Tables 3.5.1 and 3.5.2
-3 in order to include and manage cracking due to SCC for the stainless steel and dissimilar metal welds associated with the containment penetration pressure boundary with normal operating temperatures greater than 140 &deg;F. In its revision, the applicant also credited the ASME Section XI, SubSection IWE Program and 10 CFR Part 50, Appendix J Program to manage the aging effect. The applicant further indicated that the plant operating experience reviews, surface examinations, and the Appendix J tests have not revealed any indications of cracking or flaws, therefore, augmented or additional inspections are not warranted.
In its review, the staff finds the applicant's response acceptable because:  (1) the applicant's operating experience review, including the results of surface examinations and the Appendix J tests, has not revealed any indication of pitting, crevice corrosion, or SCC associated with the stainless steel containment penetration pressure boundary welds, which supports the applicant's claim that the normal stress and environmental exposure conditions are not conducive to the occurrence of SCC in the components; (2) the applicant clarified that the "air with steam or water leakage" environment was conservatively assumed for the components where event driven leakage has occurred from brackish water systems; (3) the applicant's corrective actions and service water spill response procedure provide reasonable assurance that potential adverse effects of service water leakage can be prevented or mitigate d adequately; (4) the applicant also clarified that residual weld stresses were not included in the applicant's stress analysis and it cannot be concluded with absolute certainty that the residual stresses present are not conducive to the occurrence of SCC; and (5) the applicant concluded, on the basis of the information and evaluation in response to the RAI, that there is a potential for SCC of the stainless steel and dissimilar metal welds subject to normal operating temperatures greater than 140
&deg;F exposed to an air with steam or water leakage environment. On the basis of its review, the staff's concerns described in RAI 3.5.2.2.1.7
-01 are resolved.
 
Aging Management Review Results 3-455 The staff also reviewed the applicant's ASME Section XI, SubSection IWE Program and 10 CFR Part 50, Appendix J Program and its evaluations are documented in SER Sections 3.0.3.2.13 and 3.0.3.1.18, respectively. The staff finds that the credited programs are adequate to manage the aging effect because (1) the applicant's use of the programs to manage the aging effect is consistent with the recommendation in the GALL Report and (2) the applicant's operating experience review results with the evaluation of the environmental conditions indicate no occurrence of SCC in the components and support the applicant's claim that no augmented or additional inspections are required to manage the aging effect for the components. On the basis of its review, the staff finds that the applicant's AMR results are consistent with GALL Report, Volume 2, item II.A3
-2 and the applicant satisfied the acceptance criteria in SRP
-LR Section 3.5.2.2.1.7.
Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.5.2.2.1.7 criteria. For those items that apply to LRA Section 3.5.2.2.1.7, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
Cracking Due to Cyclic Loading. LRA Section 3.5.2.2.1.8 addresses cracking due to cyclic loading. In the LRA, the applicant stated that Salem is a PWR and that BWR components including suppression pool, BWR vent header, vent line bellows, and downcomers are not applicable. The applicant also stated that the containment penetration bellows are not within the scope of license renewal because they do not perform a containment structure pressure boundary or any other intended function. The containment penetration bellows located outside of the containment are not part of the containment leakage limiting boundary per UFSAR Section 3.8.1.6.8.10. The applicant further stated that the composite containment concrete shell and carbon steel liner and penetrations (including sleeves and dissimilar metal welds) are not subject to cyclic loading induced cracking, as analysis for the piping is bounding and enveloping for stresses in the penetrations (including sleeves and dissimilar welds). Cracking due to fatigue loads is addressed, where applicable, as a TLAA for the associated piping in SER Section 4.3. Cracking is not predicted in the associated piping due to the low design loads and, therefore, is not expected in the containment liner and penetrations (including sleeves and dissimilar welds). The applicant stated that fine cracking of penetration sleeves, dissimilar welds, and the containment carbon steel liner are not expected at Salem and, therefore, the use of the ASME Section XI, SubSection IWE and 10 CFR Part 50, Appendix J programs are adequate to manage the applicable aging effects of these components without supplemental inspection activities.
The staff reviewed LRA Section 3.5.2.2.1.8 against the criteria in SRP
-LR Section 3.5.2.2.1.8, which states that cracking due to cyclic loading of the stainless steel shells (including welded joints) and penetrations (including penetration sleeves, dissimilar metal welds, and penetration bellows) could occur in PWR containments. The existing program relies on ASME Code Section XI, SubSection IWE and 10 CFR Part 50, Appendix J to manage this aging effect. However, VT
-3 visual inspection may not detect fine cracks. The GALL Report recommends further evaluation for detection of this aging effect.
On the basis of its review, the staff finds the applicant's evaluation of the AERM acceptable. No in-scope stainless steel penetration sleeves, penetration bellows, or dissimilar metal welds ar e subject to cyclic loading induced cracking at Salem
. Fatigue is addressed as a TLAA in SER Aging Management Review Results 3-456 Section 4.3. The staff's evaluations of the ASME Section XI, SubSection IWE and 10 CFR Part 50, Appendix J programs are documented in SER Sections 3.0.3.2.13 and 3.0.3.1.18, respectively.
Loss of Material (Scaling, Cracking, and Spalling) Due to Freeze
-Thaw. LRA Section 3.5.2.2.1.9 addresses loss of material (scaling, cracking, and spalling) due to freeze-thaw. In the LRA, the applicant stated that the ASME Section XI, SubSection IWL Program will be used to manage loss of material (scaling, cracking, and spalling) due to freeze-thaw of accessible containment structure concrete elements. The Salem containment structure is located in a region where weathering conditions are considered severe as shown in ASTM C 33-90, Figure 1. The applicant explained that the Salem containment structure is designed in accordance with ACI 318-63 and constructed in accordance with ACI 301-66. The applicant further explained that the type and size of aggregate, slump, cement, and additives have been established to produce durable concrete. Aggregates were tested in accordance with ASTM Specification C289
-65 for potential reactivity, as well as in accordance with ASTM Specifications C29
-60, C40-66, C127-59, C128-59, and C88
-63. The coarse aggregate was a basic igneous rock consisting of diabase and basalt that was crushed and graded to meet the detail specifications. The applicant also stated that except for the service water intake structure, the Salem structures were designed to minimize exposure to moisture to reduce the potential for water absorption, minimizing the potential for damage from freeze
-thaw conditions. The applicant further stated that an operating experience review has not identified significant loss of material (scaling, cracking, and spalling) of the accessible containment structure concrete. Inspections conducted in accordance with ASME Code Section XI, SubSection IWL identified isolated instances of minor local spalling and cracking of above
-grade concrete and grout. Evaluation of spalling and cracking concluded that these aging effects have no significant impact on structural integrity of the containment structure. Therefore, the applicant stated tha t loss of material (scaling, cracking, and spalling) due to freeze
-thaw of inaccessible concrete is insignificant and requires no aging management.
The staff reviewed LRA Section 3.5.2.2.1.9 against the criteria in SRP
-LR Section 3.5.2.2.1.9, which notes that loss of material (scaling, cracking, and spalling) due to freeze
-thaw could occur in PWR and BWR concrete containments. The existing program relies on ASME Code Section XI, SubSection IWL to manage this aging effect. The GALL Report recommends further evaluation of this aging for plants located in moderate to severe weathering conditions. GALL Report item II.A1
-2 suggests that the existing concrete have an air content of 3 percent to 6 percent. Since the applicant stated that the weathering condition is severe and an air content was not specified in the LRA, it is unclear to the staff that guidance contained in GALL Report item II.A1
-2 has been met. By a June 7, 2010 letter, the staff issued RAI 3.5.2.2.1-02 to address compliance of the Salem concrete to recommendations provided in GALL Report item II.A1-2. In its July 8, 2010 response , the applicant stated that the structural concrete mixes at Salem included fly ash and had a water
-to-cement ratio between 0.46 and 0.56. The applicant also explained that air content was not a requirement in the Salem concrete specification; however, records indicated values from 1 percent to 5 percent. The applicant also explained that although this ratio is outside the GALL Report recommended range, concrete inspections during the plant's operating history have not revealed degradation attributed to freeze
-thaw. The applicant further stated that freeze
-thaw damage is greatly influenced by the degree of saturation of the concrete and the site is designed to maximize drainage and minimize concrete exposure to moisture. The applicant stated that freeze
-thaw damage generally occurs slowly and in areas accessible for inspection, so any degradation that may occur in the future will be Aging Management Review Results 3-457 detected in a timely manner by the ASME Section XI, SubSection IWL and Structures Monitoring Program inspections, which occur on a 5
-year frequency.
The staff reviewed the applicant's response and noted that the applicant has no site
-specific operating experience with concrete freeze
-thaw degradation. In addition, the credited ASME Section XI, SubSection IWL Program visual inspections provide assurance that any future degradation will be detected prior to a loss of intended function. Even though the water-to-cement ratio is outside the GALL Report suggested range, since the applicant does not have operating experience related to freeze
-thaw degradation and has inspection programs in place, the staff finds that the applicant evaluated the AERM adequately and the staff's concern in RAI 3.5.2.2.1-02 is resolved.
Cracking Due to Expansion and Reaction with Aggregates and Increase in Porosity and Permeability Due to Leaching of Calcium Hydroxide. LRA Section 3.5.2.2.1.10 addresses cracking due to expansion and reaction with aggregates and increase in porosity and permeability due to leaching of calcium hydroxide. In the LRA, the applicant stated that the Salem containment structure is designed in accordance with ACI 318-63 and constructed in accordance with ACI 301-66. The applicant also stated that aggregates were tested in accordance with ASTM Specification C289
-65 for potential reactivity and Type II cement and fly ash were used in the concrete to provide increased resistance to leaching. The type and size of aggregate, slump, cement, and additives have been selected to produce durable concrete.
Thus, the applicant stated that cracking due to expansion and reaction with aggregates is not applicable and requires no aging management. Increase in porosity and permeability due to leaching of calcium hydroxide is not significant and the Salem ASME Section XI, SubSection IWL Program is used as the AMP.
The staff reviewed LRA Section 3.5.2.2.1.10 against the criteria in SRP
-LR Section 3.5.2.2.1.10, which states that cracking due to expansion and reaction with aggregates and increase in porosity and permeability due to leaching of calcium hydroxide could occur in concrete elements of concrete and steel containments. The GALL Report recommends further evaluation if the aggregate was not evaluated for potential expansion/reaction due to reactivity with the cementitious materials and suggests GALL AMP XI.S2, "ASME Section XI, SubSection IWL," as the AMP. GALL Report item II.A1
-6 notes that an AMP for inaccessible concrete is not required if the concrete was constructed in accordance with the recommendations of ACI 201.2R-77. The staff confirmed that the ASME Section XI, SubSection IWL Program is used at Salem to manage cracking, loss of material, and increase in porosity and permeability due to leaching of calcium hydroxide for the accessible portions of the concrete containment building. The staff's review of the applicant's ASME Section XI, SubSection IWL Program is documented in SER Section 3.0.3.1.16. In its review, the staff noted that the LRA discussed ASTM C289-65; however, it made no mention of ASTM Specifications C227 or C295, which are discussed in the GALL Report as acceptable methods for identifying aggregates that do not react within concrete. In addition, the LRA did not clearly explain that the concrete was constructed in accordance with the recommendations of ACI 201.2R-77 to demonstrate that an AMP is not required for increase in porosity and permeability due to leaching of the concrete. To address these concerns, by a June 7, 2010 letter , the staff issued RAIs 3.5.2.2.1-03 and 3.5.2.2.1
-04.
Aging Management Review Results 3-458 In its July 8, 2010 response , the applicant stated that a review of Hope Creek and Salem records indicated that the same aggregate sources were used at both plants. The aggregates at Hope Creek were shown to be non
-reactive in accordance with ASTM C295; therefore, the Salem aggregates can be considered non
-reactive as well. The applicant further stated Type II Portland Cement was used, as recommended by ACI 201.2R, and fly ash was used to improve the concrete resistance to weak acids and sulfates and, therefore, to leaching of calcium hydroxide. In addition, the applicant stated that inspections of in
-scope structures have not revealed degradation due to leaching of calcium hydroxide. Furthermore, the applicant stated that damage due to leaching would be most likely in areas exposed to flowing water, which are generally accessible and available for inspection. These areas, including the submerged components of the service water intake structure, will be used as a leading indicator for potential degradation of inaccessible areas, including inaccessible containment concrete.
The staff reviewed the applicant's responses and noted that the aggregate used in Salem concrete came from the same location as the Hope Creek aggregate, which was shown to be non-reactive using the ASTM C295 standard, as recommended in the GALL Report. The staff also noted that although the water
-to-cement ratio and air content of the Salem concrete does not fall within the GALL Report recommended range, the site does not have experience with degradation due to leaching of calcium hydroxide. In addition, inspections of accessible concrete exposed to flowing water can be used as a "leading indicator" of degradation in inaccessible areas. Since the applicant has shown the Salem aggregates to be non
-reactive, has explained how accessible concrete exposed to flowing water can be used to identify the possibility of leaching degradation in inaccessible concrete, and has programs to inspect for concrete degradation on an acceptable frequency, the staff finds that the applicant evaluated the AERM adequately and the staff's concerns in RAIs 3.5.2.2.1-03 and 3.5.2.2.1-04 are resolved. Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.5.2.2.1 criteria. For those line items that apply to LRA Section 3.5.2.2.1, the staff determines that the LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 3.5.2.2.2  Safety-Related and Other Structures and Component Supports The staff reviewed LRA Section 3.5.2.2.2 against the criteria in SRP
-LR Section 3.5.2.2.2.
Aging of Structures Not Covered by the Structures Monitoring Program
. LRA Section 3.5.2.2.2.1 addresses aging of structures not covered by the Structures Monitoring Program. In the LRA, the applicant stated that GALL Report structure Groups 2, 7, 8, and 9 do not exist, Groups 2 and 9 structures are BWR specific and thus not applicable, and there are no Group 7 concrete tanks.
Concrete walls and structural steel with a missile barrier function are associated with some buildings and are addressed as an integral part of those parent structures. The applicant further stated that Salem has no separate Group 7 or 8 missile barrier structures. Steel tanks are addressed as a part of the mechanical systems and not as a Group 8 structure. Salem AMRs concluded that certain concrete aging effects or mechanisms identified in the GALL Report are not applicable to some of the Groups 1, 3, 4, and 5 structures as explained below and require no aging management. However, the applicant explained that Groups 1, 3, 4, and 5 accessible structures will be monitored for loss of material, cracking, Aging Management Review Results 3-459 increase in porosity and permeability, and loss of bond through the Structures Monitoring Program regardless of the causal mechanism.
The staff reviewed LRA Section 3.5.2.2.2.1 against the criteria in SRP
-LR Section 3.5.2.2.2.1, which states that the GALL Report recommends further evaluation of certain structure/aging effect combinations if they are not covered by the structures monitoring program, including
 
(1) cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel for Groups 1-5, 7, and 9 structures; (2) increase in porosity and permeability, cracking, and loss of material (spalling, scaling) due to aggressive chemical attack for Groups 1-5, 7, and 9 structures; (3) loss of material due to corrosion for Groups 1-5, 7, and 8 structures; (4) loss of material (spalling, scaling) and cracking due to freeze
-thaw for Groups 1-3, 5, and 7
-9 structures; (5) cracking due to expansion and reaction with aggregates for Groups 1-5 and 7-9 structures; (6) cracks and distortion due to increased stress levels from settlement for Groups 1-3 and 5-9 structures; and (7) reduction in foundation strength, cracking, and differential settlement due to erosion of porous concrete subfoundation for Groups 1-3 and 5-9 structures. In addition, lockup due to wear may occur for Lubrite radial beam seats in BWR drywells, RPV support shoes for PWRs with nozzle supports, steam generator supports, and other sliding support bearings and sliding support surfaces. The existing program relies on the structures monitoring program or ASME Code Section XI, SubSection IWF to manage this aging effect. The GALL Report recommends further evaluation only for structure
-aging effect combinations not within the ISI (IWF) or structures monitoring programs
.  (1) Cracking, Loss of Bond, and Loss of Material (Spalling, Scaling) Due to Corrosion of Embedded Steel for Groups 1-5, 7, and 9 Structures In the LRA, the applicant stated that cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel for Groups 1, 3, 4, and 5 structures are monitored by the Structures Monitoring Program and thus, further evaluation is not necessary.
The staff confirmed that Groups 1, 3, 4, and 5 structures subject to this AMR are in-scope of the applicant's Structures Monitoring Program. Therefore, the staff finds that the criteria of SRP
-LR Section 3.5.2.2.2.1 have been met and no further evaluation is required.  (2) Increase in Porosity and Permeability, Cracking, and Loss of Material (Spalling, Scaling) Due to Aggressive Chemical Attack for Groups 1-5, 7, and 9 Structures In the LRA, the applicant stated that increase in porosity and permeability, cracking, and loss of material (spalling, scaling) due to aggressive chemical attack for Groups 1, 3, 4, and 5 structures are monitored through the Structures Monitoring Program and thus, further evaluation is not necessary. The applicant also stated that leakage of treated borated water from the reactor cavity liners, while contained within the containment structures, has come into contact with the supporting concrete during refueling outages. In the LRA, the applicant further stated that the effects of borated water on the containment interior concrete were evaluated and found to be bounded by the effects due to similar leaks in the fuel handling building from the spent fuel pools. The applicant stated that an analysis was conducted which shows that the effects of borated water on the reinforced concrete and structural margin is not significant and has no impact on structural integrity of the internal containment structures, the spent fuel pool, or the fuel handing building through the period of extended operation. 
 
Aging Management Review Results 3-460  Since leakage of treated borated water from the reactor cavity liners, as well as the spent fuel pool liners, was noted to be occurring and has come into contact with the supporting concrete, it is unclear to the staff that leakage of the borated water has not resulted in degradation of either the concrete or embedded steel reinforcement that is inaccessible for inspection. Therefore, by a April 15, 2010 letter , the staff issued RAIs B.2.1.33-1 and B.2.1.33
-2 requesting that the applicant provide more details on the spent fuel pool and the reactor cavity leakage and discuss how the integrity of inaccessible portions of the concrete and embedded steel reinforcement will be demonstrated during the period of extended operation.
The applicant responded by a May 13, 2010 letter. The staff's review of the responses and resolution of these issues can be found in the Structures Monitoring Program evaluation documented in SER Section 3.0.3.2.15. Further discussion of how the applicant addresses aging of inaccessible concrete can be found in SER Section 3.5.2.2.2, "Aging of Inaccessible Areas."
The staff confirmed that Groups 1, 3, 4, and 5 structures subject to this AMR are in-scope of the Structures Monitoring Program. Therefore, the staff finds that the criteria of SRP-LR Section 3.5.2.2.2.1 have been met and no further evaluation is required.
  (3) Loss of Material Due to Corrosion for Groups 1
-5, 7, and 8 Structures In the LRA, the applicant stated that loss of material due to corrosion for Groups 1, 3, 4, and 5 structures and component supports is monitored through the Structures Monitoring Program and thus, a further evaluation is not necessary.
The staff confirmed that Groups 1, 3, 4, and 5 structures subject to this AMR are in-scope of the Structures Monitoring Program. Therefore, the staff finds that the criteria of SRP-LR Section 3.5.2.2.2.1 have been met and no further evaluation is required.
  (4) Loss of Material (Spalling, Scaling) and Cracking Due to Freeze
-Thaw for Groups 1-5 and 7-9 Structures In the LRA, the applicant stated that loss of material (spalling, scaling) and cracking due to freeze-thaw for Groups 1, 3, and 5 structures are monitored through the Structures Monitoring Program and thus, further evaluation is not necessary. The applicant further stated that Group 4 structures are inside the containment structure and protected from repeated freeze
-thaw; thus not subject to loss of material and cracking due to freeze-thaw. The staff confirmed that Groups 1, 3, 4, and 5 structures subject to this AMR are in-scope of the Structures Monitoring Program. Therefore, the staff finds that the criteria of SRP-LR Section 3.5.2.2.2.1 have been met and no further evaluation is required.
  (5) Cracking Due to Expansion and Reaction with Aggregates for Groups 1-5 and 7-9 Structures In the LRA, the applicant stated that cracking due to reaction with aggregates for Groups 1, 3, 4, and 5 structures is not applicable as concrete for Groups 1, 3, 4, and 5 structures was constructed in accordance with ACI 301
-66 and aggregates were tested in accordance with ASTM Specification C289
-65 for potential reactivity. The type and size of aggregate, slump, cement, and additives have been selected to produce durable concrete. Thus, the applicant stated that cracking due to expansion and reaction with aggregates is not applicable and requires no aging management. Nevertheless, Aging Management Review Results 3-461 concrete cracking due to any mechanism is monitored through the Structures Monitoring Program.
The staff confirmed that Groups 1, 3, 4, and 5 structures subject to this AMR are in-scope of the Structures Monitoring Program. Therefore, the staff finds that the criteria of SRP-LR Section 3.5.2.2.2.1 have been met and no further evaluation is required.
  (6) Cracks and Distortion Due to Increased Stress Levels from Settlement for Groups 1-3 and 5-9 Structures In the LRA, the applicant stated that Groups 1, 3, 4, and 5 structures are potentially subject to cracks and distortion due to increased stress levels from settlement. A dewatering system and porous concrete subfoundations are not used at Salem. The applicant further stated that structures whose foundations are founded on soil or the Vincentown Formation are potentially subject to cracks and distortion due to increased stress levels from settlement. Certain Group 3 structures are founded on concrete piles, which are encased in steel, and other Group 3 structures are founded on soil. For those structures founded on soil or the Vincentown Formation, cracks and distortion due to increased stress levels from settlement are applicable and will be monitored under the Structures Monitoring Program. For those Group 3 structures founded on concrete piles encased in steel, cracks and distortion due to increased stress levels from settlement is not applicable. Regardless, Groups 1, 3, 4, and 5 structures are monitored under the Structures Monitoring Program for cracks and distortion due to increased stress levels from settlement.
The staff confirmed that Groups 1, 3, 4, and 5 structures subject to this AMR are in-scope of the applicant's Structures Monitoring Program. Therefore, the staff finds that the criteria of SRP
-LR Section 3.5.2.2.2.1 have been met and no further evaluation is required.  (7) Reduction in Foundation Strength, Cracking, and Differential Settlement Due to Erosion of Porous Concrete Subfoundation for Groups 1-3 and 5-9 Structures In the LRA, the applicant stated that Groups 1, 3, 4, and 5 structures are not subject to reduction in foundation strength, cracking, and differential settlement due to erosion of the porous concrete subfoundation because porous concrete subfoundations were not used at Salem.
Based on its review of documents supporting the LRA, the staff agrees this aging effect is not applicable because Salem has no porous concrete subfoundations. 
  (8) Lockup Due to Wear for Lubrite Radial Beam Seats in BWR Drywell and Other Sliding Support Surfaces In the LRA, the applicant stated that the applicable material is Lubrite. The steam generator supports include pinned steel connections and Lubrite plates. Lockup due to wear in the indoor
-air environment is managed using the ASME Section XI, SubSection IWF Program, therefore, no further evaluation is necessary. Sliding surfaces for other supports are pinned steel connections or carbon steel sliding surfaces for which Lubrite is not used. The applicant stated that the RPV support shoes for the PWR nozzle supports, piping supports, RCP supports, and heat exchanger supports include sliding steel surfaces. Aging management of these surfaces is through the ASME Section XI, SubSection IWF Program.
 
Aging Management Review Results 3-462  The staff confirmed that sliding supports are within the scope of the ASME Section XI, SubSection IWF Program. SER Section 3.5.2.1.6 documents the staff's review for lockup due to wear for Lubrite radial beam seats in BWR drywell and other sliding support surfaces. Since the sliding supports are within the scope of the ASME Section XI, SubSection IWF Program, the staff finds that the criteria of SRP
-LR Section 3.5.2.2.2.1 have been met and no further evaluation is required.
Based on the programs identified above, the staff concludes that the applicant's programs meet SRP-LR Section 3.5.2.2.2.1 criteria. For those line items that apply to LRA Section 3.5.2.2.2.1, the LRA is consistent with the GALL Report and the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by
 
10 CFR 54.21(a)(3).
Aging Management of Inaccessible Areas. LRA Section 3.5.2.2.2.2 addresses aging management of inaccessible areas (below
-grade inaccessible concrete areas of Groups 1, 3, 5, and 7-9 structures).
The staff reviewed LRA Section 3.5.2.2.2.2 against the criteria in SRP
-LR Section 3.5.2.2.2.2, which states that the GALL Report recommends further evaluation of certain structure/aging effect combinations (1) loss of material (spalling, scaling) and cracking due to freeze
-thaw in below-grade inaccessible concrete areas of Groups 1-3, 5, and 7
-9 structures for plants located in moderate to severe weathering conditions; (2) cracking due to expansion and reaction with aggregates in below
-grade inaccessible concrete areas of Groups 1
-5 and 7-9 structures if concrete was not constructed in accordance with the recommendations in ACI 201.2R-77; (3) cracks and distortion due to increased stress levels from settlement and reduction of foundation strength, cracking, and differential settlement due to erosion of porous concrete subfoundations in below
-grade inaccessible concrete areas of Groups 1
-3, 5, and 7
-9 structures for plants whose structures are not included within the scope of the applicant's structures monitoring program; (4) increase in porosity and permeability, cracking, and loss of material (spalling, scaling) due to aggressive chemical attack and cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel in below
-grade inaccessible concrete areas of Groups 1, 3, 5, and 7-9 structures if the environment is aggressive; and (5) increase in porosity and permeability and loss of strength due to leaching of calcium hydroxide in below
-grade inaccessible concrete areas of Groups 1-3, 5, and 7
-9 structures if the concrete was not constructed in accordance with the recommendations in ACI 201.2R-77.  (1) Loss of material (spalling, scaling) and cracking due to freeze
-thaw could occur in below-grade inaccessible concrete areas of Groups 1-3, 5, and 7
-9 structures.
In the LRA, the applicant stated that Groups 1, 3, and 5 structures are located in a region where weathering conditions are considered severe as shown in ASTM C 33-90, Figure 1. GALL structure Groups 2, 7, 8, and 9 do not exist at Salem. Group 4 structures are containment internal structures and are not exposed to freeze
-thaw conditions. The applicant further stated that concrete for Groups 1, 3, 4, and 5 structures is designed in accordance with ACI 318
-63 and constructed in accordance with ACI 301-66, and testing of the concrete materials was in accordance with applicable ASTM standards as required by ACI. The Type II Portland cement conforms to ASTM C 150 and fly ash was used in the concrete mixtures. Concrete aggregates Aging Management Review Results 3-463 conform to the requirements of ASTM C 33-66. The type and size of aggregate, slump, cement, and additives have been established to produce durable concrete. Neither calcium chloride nor admixtures containing calcium chloride or other chlorides, sulfides, or nitrates were used in the concrete mixtures. The applicant also stated that structures were designed to minimize exposure to moisture to minimize water absorption, reducing the potential for damage from freeze
-thaw conditions. The condition of concrete in the service water intake structure, as well as abov e-grade concrete of Groups 1, 3, and 5 structures is used as an indicator for inaccessible concrete and provides reasonable assurance that degradation of inaccessible structures will be detected before loss of an intended function. The LRA further states that a review of operating experience has not identified significant loss of material and cracking of the accessible Groups 1, 3, and 5 structures concrete. Therefore, the applicant stated that loss of material (spalling, scaling) and cracking due to free ze-thaw of inaccessible concrete are insignificant and require no aging management. However, inaccessible concrete will be inspected if excavated for any reason, as required by the Structures Monitoring Program.
The staff reviewed LRA Section 3.5.2.2.2.2.1 against the criteria in SRP
-LR Section 3.5.2.2.2.2.1, which states that further evaluation is required for loss of material (spalling, scaling) and cracking due to freeze
-thaw in below
-grade inaccessible concrete areas of Groups 1-3, 5, and 7
-9 structures for plants subjected to moderate to severe weathering conditions. The GALL Report suggests that the existing concrete have an air content of 3 percent to 6 percent. The air content recommended for concrete resistance to freezing and thawing by ACI 201.2R is 4.5 percent to 7.5 percent for severe exposure with a +/-1.5 percent tolerance. The GALL Report also suggests a water
-to-cement ratio between 0.35 and 0.45 for concrete exposed to potential freeze
-thaw conditions. The staff's review of the Structures Monitoring Program is documented in SER Section 3.0.3.2.15. The staff noted that in LRA Section 3.5.2.2.2.2.1, neither an air content nor a water
-to-cement ratio was specified for the Salem concrete. To address this issue and compliance of the concrete to recommendations provided in ACI 201.2R, the staff issued RAI 3.5.2.2.1-02 by letter dated June 7, 2010. The applicant responded by letter dated July 8, 2010. A discussion of the staff's review of the response, as well as the staff's acceptance of the applicant's approach to aging management of concrete degradation due to freeze
-thaw, is included in SER Section 3.5.2.2.1, "Loss of Material Due to Freeze
-Thaw."  Based on its review, the staff concludes that the applicant has adequately evaluated concrete degradation due to freeze
-thaw and no additional plant
-specific program is required for inaccessible areas.
  (2) Cracking due to expansion and reaction with aggregates could occur in below
-grade inaccessible concrete areas for Groups 1-5 and 7-9 structures. In the LRA, the applicant stated that at Salem the concrete portions of Groups 1, 3, 4, and 5 structures are designed in accordance with ACI 318-63 and constructed in accordance with ACI 301-66 using the same concrete specification and standards as the containment structure. The applicant further stated that Groups 2, 7, 8, and 9 structures are not found at Salem. Aggregates were tested in accordance with ASTM Specification C289-65 for potential reactivity. The Type II Portland cement conforms to ASTM C 150 and fly ash was also used in the concrete mixtures. Thus, the applicant concluded that cracking due to expansion and reaction with aggregates is not significant and requires no aging management. However, the applicant further stated that inaccessible concrete for Groups 1, 3, and 5 structures will be inspected for cracking due to any mechanism if Aging Management Review Results 3-464 excavated for any reason, as required by the Structures Monitoring Program. Group 4 containment internal concrete structures are accessible and inspected by the Structures Monitoring Program.
The staff reviewed LRA Section 3.5.2.2.2.2.2 against the criteria in SRP
-LR Section 3.5.2.2.2.2.2, which states that the GALL Report recommends further evaluation of inaccessible areas of these groups of structures if the concrete was not constructed in accordance with the recommendations in ACI 201.2R-77. GALL Report item III.A1
-2 states that investigations, tests, and petrographic examinations of aggregates performed in accordance with ASTM C295
-54 or ASTM C 227-50 can demonstrate that the aggregate is not reactive within the reinforced concrete. If either of these conditions is met, the GALL Report notes that aging management is not necessary.
In its review, the staff noted that the LRA discussed ASTM C289-65; however, it made no mention of ASTM C227 or C295 which are discussed in the GALL Report as acceptable methods for identifying aggregates that do not react within concrete. In addition, the LRA did not clearly explain that the concrete was constructed in accordance with the recommendations of ACI 201.2R-77 to demonstrate that an AMP is not required.
B y a June 7, 2010 letter , the staff issued RAI 3.5.2.2.1-03 to address these concerns. The applicant responded by a July 8, 2010 letter. A discussion of the staff's review of the response, as well as the staff's acceptance of the applicant's evaluation of aging effects due to reactive aggregates, is included in SER Section 3.5.2.2.1, "Cracking Due to Expansion and Reaction with Aggregates."
On the basis of its review, the staff finds that the aggregates used at Salem are nonreactive. Therefore, cracking due to expansion and reaction with aggregates in below-grade inaccessible concrete areas for Groups 1-5 and 7-9 structures are not aging effects for concrete elements and no additional plant
-specific program is required.
  (3) Cracks and distortion due to increased stress levels from settlement and reduction of foundation strength, cracking, and differential settlement due to erosion of porous concrete subfoundations could occur in below
-grade inaccessible concrete areas of Groups 1-3, 5, and 7
-9 structures.
In the LRA, the applicant stated that Salem Groups 1, 3, 4, and 5 structures are potentially subject to cracks and distortion due to increased stress levels from settlement. However, the applicant stated that the aging effect/mechanism is not significant. The Salem design does not employ a dewatering system to control settlement and does not include porous concrete subfoundations. The applicant explained that measurements made throughout plant construction and during initial operation indicated a maximum settlement of approximately 12.7 millimeters (0.5 inch), which is not significant. The applicant further explained that the condition of the accessible and above
-grade concrete is used as an indicator for the condition of the inaccessible and below
-grade concrete and provides reasonable assurance that degradation of inaccessible structures will be detected before a loss of an intended function. In the unlikely event of cracks and distortion due to settlement occurring in below-grade or inaccessible concrete, the cracks and distortion would propagate into the above-grade or accessible concrete areas, and corrective actions will be initiated to evaluate the condition of inaccessible portions of the structures and determine if excavation of concrete for inspection is warranted. It is further stated in the LRA that Salem has not experienced cracks and distortion due to increased stress levels from settlement of structures. Inaccessible concrete for Groups 1, 3, and 5 structures will be Aging Management Review Results 3-465 inspected for cracking and distortion due to settlement if excavated for any reason, as required by the Structures Monitoring Program. Since the Groups 1, 3, 4, and 5 structures are monitored under the Structures Monitoring Program for cracks and distortion due to increased stress levels from settlement and a dewatering system is not used, further evaluation is not necessary.
The staff reviewed LRA Section 3.5.2.2.2.2.3 against the criteria in SRP
-LR Section 3.5.2.2.2.2.3, which states that the GALL Report recommends verification of the continued functionality of the dewatering system during the period of extended operation if the plant's CLB credits a dewatering system. The GALL Report recommends no further evaluation if this activity and these aging effects are included within the scope of the applicant's Structures Monitoring Program.
On the basis of its review, the staff determined that cracks and distortion due to increased stress levels from settlement and reduction of foundation strength, cracking, and differential settlement due to erosion of porous concrete subfoundations in below-grade inaccessible concrete areas of Groups 1-3, 5, and 7
-9 structures are not plausible aging effects due to the absence of these aging mechanisms. Salem does not use a dewatering system, and there are no porous subfoundations on the site. In addition, the applicant monitors the above
-grade exposed concrete for the aging effect of cracking due to settlement under the Structures Monitoring Program. Therefore, no additional plant
-specific program is required. The staff's evaluation of the applicant's Structures Monitoring Program is documented in SER Section 3.0.3.2.15.
  (4) Increase in porosity and permeability, cracking, and loss of material (spalling, scaling) due to aggressive chemical attack and cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel could occur in below
-grade inaccessible concrete areas of Groups 1-3, 5, and 7
-9 structures.
In the LRA, the applicant stated that for Groups 1, 3, and 5 structures, the inaccessible below-grade reinforced concrete is subject to an aggressive environment due to elevated chloride levels. In the LRA, the applicant also stated that Groups 1, 3, and 5 structures are designed in accordance with ACI 318-63 and constructed in accordance with ACI 301-66. The Structures Monitoring Program includes inspection of concrete to detect indications of increase in porosity and permeability, cracking, and loss of material (spalling, scaling) due to aggressive chemical attack and cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel. The applicant further stated that degradation of concrete due to cracking, loss of bond, and loss of material due to corrosion of embedded steel has not been experienced at Salem. Exposed portions of below
-grade concrete will be examined by the Structures Monitoring Program when excavated for any reason, and groundwater chemistry will be monitored periodically in accordance with the enhanced Structures Monitoring Program. Also, the enhanced periodic inspections of the submerged portions of the intake structure will be used as indicators for the condition of below
-grade structures. The applicant further stated that due to groundwater chemistry being bounded by river water chemistry, the use of submerged structures as a leading indicator for the potential degradation of below-grade structures provides reasonable assurance that degradation of inaccessible structures will be detected before a loss of an intended function. The applicant explained that if significant concrete degradation is identified at the service water intake structure, corrective actions will be initiated to evaluate the condition of inaccessible portions of the Groups 1, 3, and 5 structures. The applicant further stated that leakage of the spent fuel pools in the fuel handling building has resulted in detectable levels of Aging Management Review Results 3-466 borated water in the seismic gap between the auxiliary building and the containment structure. Analyses indicate that the effects of borated water on the reinforced concrete and structural margin is not significant and has no impact on structural integrity of the spent fuel pool or the fuel handing building through the period of extended operation.
The staff reviewed LRA Section 3.5.2.2.2.2.4 against the criteria in SRP
-LR Section 3.5.2.2.2.2.4, which states that the GALL Report recommends further evaluation of plant-specific programs to manage these aging effects and mechanisms in inaccessible areas of these groups of structures if the environment is aggressive. In the GALL Report, it is noted that for inaccessible areas of plants with non
-aggressive groundwater/soil (i.e., pH greater than 5.5, chlorides less than 500 ppm, or sulfates less than 1,500 ppm), as a minimum the following should be considered (a) examinations of the exposed portions of the below
-grade concrete, when excavated for any reason and (b) periodic monitoring of below-grade water chemistry, including consideration of potential seasonal variations. Since the applicant does not have definite plans for inspections of inaccessible areas and the groundwater is aggressive, it is unclear to the staff that this is an adequate approach to managing aging of inaccessible concrete structures subjected to aggressive groundwater.
B y a April 15, 2010 letter, the staff issued RAI B.2.1.33-3 requesting that the applicant provide the locations and results of past groundwater sampling, as well as a basis to demonstrate the chloride levels in the groundwater were not causing degradation of the inaccessible concrete.
The applicant responded by a May 13, 2010 letter. A discussion of the staff's review of the response, as well as the staff's acceptance of the applicant's evaluation of aging effects due to aggressive groundwater, is included in the staff's review of the Structures Monitoring Program documented in SER Section 3.0.3.2.15.
During its review, the staff also noted that borated water leakage from the spent fuel pool and refueling cavity liners may be causing degradation of the concrete or embedded steel reinforcement that is inaccessible for inspection. Therefore, b y a April 15, 2010 letter , the staff issued RAIs B.2.1.33-1 and B.2.1.33
-2 requesting that the applicant provide more details on the spent fuel pool and the reactor cavity leakage and discuss how the integrity of inaccessible portions of the concrete and embedded steel reinforcement will be demonstrated during the period of extended operation.
The applicant responded by a Ma y 13, 2010 letter. In its response, the applicant explained that no degradation has been detected during past inspections and that a concrete core will be taken from the spent fuel pool at a known leakage location to verify no degradation has occurred. The staff found this approach acceptable. A more detailed discussion of the staff's review and resolution of this issue can be found in the Structures Monitoring Program evaluation documented in SER Section 3.0.3.2.15.
Based on its review, including RAIs B.2.1.33-1 and B.2.1.33
-2, the staff concludes that the applicant has demonstrated that the aging effects due to aggressive chemical attack and corrosion of embedded steel will be adequately managed and no further evaluation is required.
  (5) Increase in porosity and permeability and loss of strength due to leaching of calcium hydroxide could occur in below
-grade inaccessible concrete areas of Groups 1-3, 5, and 7-9 structures In the LRA, the applicant stated that leaching of calcium hydroxide is applicable for a flowing water environment that may occur to a limited extent in accessible or Aging Management Review Results 3-467 inaccessible portions of Groups 1, 3, 4, and 5 structures. The applicant stated that operating experience has found that increase in porosity and permeability and loss of strength due to leaching of calcium hydroxide is not significant and is adequately managed by the Structures Monitoring Program. In the LRA, the applicant further stated that inaccessible portions of the Group 5 structures may be subject to leaching of calcium hydroxide due to the known leakage of the borated water from the spent fuel pools. In 2006, an inspection was conducted in accordance with ACI 349 to assess the structural condition of the spent fuel pool and the fuel handling building. The inspections identified no significant degradations or areas of structural distress. A similar inspection was conducted in 2009 to determine if any changes have occurred since the 2006 inspection with no significant changes noted. The applicant further stated that during the investigative phase of the spent fuel pool liner leakage, it was determined that leakage through small cracks in the stainless steel liner seam and plug welds did not drain properly because of clogged drains. As a result, water pressure behind the liner increased and forced borated water through small cracks in concrete and in the small gap between the liner and concrete. Maintenance activities were established to ensure the leak-chase system drains are cleared to allow drainage of the leakage. These activities will continue through the period of extended operation. The applicant explained that this reduces the amount of concrete exposed to borated water and ensures that the analysis performed to determine the impact of the borated water on the reinforced concrete remains bounding. The applicant further explained that the Structures Monitoring Program includes the reinforced concrete trench that collects the borated water drainage from the spent fuel pool telltale drains. Monitoring the reinforced concrete trench provides an indication of the actual concrete degradation in the Group 5 inaccessible areas and provides reasonable assurance that degradation of inaccessible structures will be detected before a loss of an intended function. The applicant explained that in the event inspection of the concrete trench identifies significant concrete degradation, corrective actions will be initiated to evaluate the condition of inaccessible portions of the Group 5 structures potentially exposed to borated water leakage. The staff reviewed LRA Section 3.5.2.2.2.2.5 against the criteria in SRP
-LR Section 3.5.2.2.2.2.5, which states that the GALL Report recommends further evaluation of this aging effect for inaccessible areas of Groups 1-3, 5, and 7
-9 structures if concrete was not constructed in accordance with the recommendations in ACI 201.2R-77. In its review, the staff noted that the LRA did not clearly explain that the concrete was constructed in accordance with the recommendations of ACI 201.2R-77 to demonstrate that further evaluation is not required for increase in porosity and permeability due to leaching of calcium hydroxide in inaccessible concrete. To address this concern, the staff issued RAI 3.5.2.2.1-04 by a Ju ne 7, 2010 letter. The applicant responded by a July 8, 2010 letter. A discussion of the staff's review of the response, as well as the staff's acceptance of the applicant's evaluation of aging effects due to leaching of calcium hydroxide, is included in SER Section 3.5.2.2.1, "Increase in Porosity and Permeability Due to Leaching of Calcium Hydroxide."
During its review, the staff also noted that leakage of treated borated water from the reactor cavity liners, as well as the spent fuel pool liners, was noted to be occurring and has come into contact with the supporting concrete. It is unclear to the staff that leakage of the borated water has not resulted in degradation of either the concrete or embedded steel reinforcement that is inaccessible for inspection. Therefore, by a April 15, 2010 Aging Management Review Results 3-468 letter, the staff issued RAIs B.2.1.33-1 and B.2.1.33
-2 requesting that the applicant provide more details on the spent fuel pool and the reactor cavity leakage and discuss how the integrity of inaccessible portions of the concrete and embedded steel reinforcement will be demonstrated during the period of extended operation.
The applicant responded by a May 13, 2010 letter. In its response the applicant explained that no degradation has been detected during past inspections and that a concrete core will be taken from the spent fuel pool at a known leakage location to verify no degradation has occurred. The staff found this approach acceptable. A more detailed discussion of the staff's review and resolution of this issue can be found in the Structures Monitoring Program evaluation documented in SER Section 3.0.3.2.15.
Based on its review, including RAIs B.2.1.33-1 and B.2.1.33
-2, the staff concludes that the applicant has demonstrated that the aging effects due to leaching of calcium hydroxide will be adequately managed and no further evaluation is required.
Based on the programs and evaluations identified, the staff concludes that the applicant's programs meet the criteria of SRP
-LR Section 3.5.2.2.2.2. For those line items that apply to LRA Section 3.5.2.2.2.2, the LRA is consistent with the GALL Report and the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
Reduction of Strength and Modulus of Concrete Structures Due to Elevated Temperature
. LRA Section 3.5.2.2.2.3 addresses reduction of strength and modulus of concrete structures due to elevated temperature for Groups 1-5 structures. In the LRA, the applicant stated that Group 2 structures are BWR specific and Groups 1, 3, 4, and 5 concrete structures are not subject to general area temperatures greater than 150
&deg;F. Group 1 structures (control room area) and Group 3 structures, which include areas within the EQ program, are exposed to indoor conditioned air temperatures not greater than 120
&deg;F during normal operation. Group 4 structures are exposed to air temperatures inside the containment structure. The applicant explained that the TSs and UFSAR limit the bulk air temperature inside the building during normal plant operation to 120
&deg;F. The bulk air temperature is maintained within the TS limits by recirculating air through cooling coils and by forced air through the reactor shield and reactor nozzle support areas. Group 3 structures, which include areas not within the EQ program, and Group 5 structures (fuel handling building) are structures with limited heat sources. Therefore, normal temperatures are less than 150
&deg;F. The applicant further explained that Groups 1, 3, 4, and 5 concrete structures are not subject to a local temperature greater 200
&deg;F. Penetration seal technology is designed to prevent surrounding concrete from exceeding 200
&deg;F (penetration seal specification). Plant operating experience has not identified elevated local temperature as a concern for the Groups 1, 3, 4, and 5 concrete structures.
The staff reviewed LRA Section 3.5.2.2.2.3 against the criteria in SRP
-LR Section 3.5.2.2.2.3, which states that reduction of strength and modulus of concrete due to elevated temperatures may occur in PWR and BWR Groups 1-5 concrete structures. ACI 349-85 specifies the concrete temperature limits for normal operation or any other long
-term period and states that general area temperatures shall not exceed 65
&deg;C (150 &deg;F) except for local areas that are permitted to have temperatures not to exce ed 93 &deg;C (200 &deg;F). The GALL Report recommends further evaluation of a plant
-specific program if any portion of in
-scope concrete structures exceeds these limits.
 
Aging Management Review Results 3-469 The staff noted that Groups 1-5 concrete elements do not exceed temperature limits associate d with aging degradation due to elevated temperature. On the basis of its review, the staff finds that reduction in strength and modulus of elasticity due to elevated temperatures in concrete areas of Groups 1-5 structures is not a plausible AERM because concrete temperatures are below limits specified in ACI 349-85. Therefore, the staff finds that this is not an AERM for these components because the necessary condition does not exist.
Aging Management of Inaccessible Areas for Group 6 Structures. LRA Section 3.5.2.2.2.4 addresses aging management of inaccessible areas for Group 6 structures
. The staff reviewed LRA Section 3.5.2.2.2.4 against the criteria in SRP
-LR Section 3.5.2.2.2.4.
  (1) Increase in porosity and permeability, cracking, and loss of material (spalling, scaling) due to aggressive chemical attack and cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel could occur in below
-grade inaccessible concrete areas of Group 6 structures.
In the LRA, the applicant stated that the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program, as implemented through the Structures Monitoring Program, will be used to manage cracking, loss of bond, and loss of material due to corrosion of embedded steel in accessible above
-grade and submerged areas of water
-control structures (Group 6 structures). The applicant also stated that river water chloride content is variable and ranges from 10,000 to 15,000 ppm. The groundwater and river water are, therefore, considered aggressive environments due to chloride levels. The reinforced concrete for Group 6 structures is designed in accordance with ACI 318-63 and constructed in accordance with ACI 301-66. Exposed portions of below
-grade concrete will be examined by the Structures Monitoring Program when excavated for any reason and groundwater chemistry will be monitored periodically in accordance with the Structures Monitoring Program. The applicant also stated that the enhanced 5
-year periodic inspections of the submerged portions of the intake structure will be used as indicators for the condition of below-grade portions of the structures. In the event inspection of submerged structures identifies significant concrete degradation at the service water intake structure, corrective actions will be initiated to evaluate the condition of inaccessible below
-grade portions of the Group 6 structures.
The staff reviewed LRA Section 3.5.2.2.2.4.1 against the criteria in SRP
-LR Section 3.5.2.2.2.4.1, which states that the GALL Report recommends further evaluation of plant-specific programs to manage these aging effects in inaccessible areas if the environment is aggressive. The staff's review for these aging effects for inaccessible concrete elements of Groups 1-3, 5, and 7
-9 structures is documented in SER Section 3.5.2.2.2, "Aging Management of Inaccessible Areas."  The staff noted that inspections of Group 6 structures are performed under the Structures Monitoring Program, which is consistent with and integrates the elements of the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program. The staff's review of the Structures Monitoring Program is documented in SER Section 3.0.3.2.15.
Since the applicant does not have definite plans for inspections of inaccessible areas and the groundwater is aggressive, it is unclear to the staff that this is an adequate approach to managing aging of inaccessible concrete structures subjected to aggressive environments. Therefore, by letter dated April 15, 2010, the staff issued RAI B.2.1.33-3 Aging Management Review Results 3-470 requesting that the applicant provide the locations and results of past groundwater sampling, as well as a basis to demonstrate that the chloride levels in the groundwater were not causing degradation of the inaccessible concrete.
The applicant responded by letter dated May 13, 2010. A discussion of the staff's review of the response, as well as the staff's acceptance of the applicant's evaluation of aging effects due to aggressive groundwater, is included in the staff's review of the Structures Monitoring Program documented in SER Section 3.0.3.2.15.
Based on its review, the staff concludes that the applicant has demonstrated that the aging effects due to aggressive chemical attack and corrosion of embedded steel will be adequately managed and no further evaluation is required for inaccessible areas of Group 6 structures.
  (2) Loss of material (spalling, scaling) and cracking due to freeze
-thaw that could occur in below-grade inaccessible concrete areas of Group 6 structures.
In the LRA, the applicant stated that the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants, as implemented by the Structures Monitoring Program, will be used to manage loss of material (spalling, scaling) and cracking due to freeze
-thaw in accessible areas of water
-control structures (Group 6 structures). Group 6 structures are located in a region where weathering conditions are considered severe as shown in ASTM C33
-90, Figure
: 1. The applicant further stated that structures are designed in accordance with ACI 318-63 and constructed in accordance with ACI 301-66 that precludes significant loss of material (spalling, scaling) and cracking due to freeze
-thaw. The applicant also stated that the condition of exposed above-grade and submerged concrete of Group 6 structures is used as an indicator for inaccessible concrete and provides reasonable assurance that degradation of inaccessible structures will be detected before a loss of an intended function. In the event inspection of above
-grade concrete structures or submerged structures identifies significant concrete degradation due to freeze
-thaw, corrective actions will be initiated to evaluate the condition of inaccessible below-grade portions of Group 6 structures. The applicant stated that review of operating experience has not identified significant signs of distress due to freeze
-thaw of concrete components of Group 6 structures; therefore, loss of material (spalling, scaling) and cracking due to freeze
-thaw of inaccessible concrete are insignificant and require no aging management.
The staff reviewed LRA Section 3.5.2.2.2.4.2 against the criteria in SRP
-LR Section 3.5.2.2.2.4.2, which states that the GALL Report recommends further evaluation of this aging effect for inaccessible areas for plants located in moderate to severe weathering conditions. The staff's review for these aging effects for inaccessible concrete elements of Groups 1-3, 5, and 7
-9 structures is documented in SER Section 3.5.2.2.2, "Aging Management of Inaccessible Areas."  The staff noted that inspections of accessible Group 6 structures are performed under the Structures Monitoring Program, which is consistent with and integrates the elements of the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program. The staff's review of the Structures Monitoring Program is documented in SER Section 3.0.3.2.15. GALL Report item III.A6
-5 suggests that aging management i s not necessary if the existing concrete has an air content of 3 percent to 6 percent and a water-to-cement ratio between 0.35 and 0.45 for concrete exposed to potential freeze-thaw conditions. The staff noted that in LRA Section 3.5.2.2.2.4.2, neither an air content nor a water
-to-cement ratio is specified for the Salem concrete.
 
Aging Management Review Results 3-471  To address this issue and compliance of the concrete to recommendations provided in ACI 201.2R, the staff issued RAI 3.5.2.2.1-02 by letter dated June 7, 2010. The applicant responded by letter dated July 8, 2010. A discussion of the staff's review of the response, as well as the staff's acceptance of the applicant's approach to aging management of concrete degradation due to freeze
-thaw, is included in SER Section 3.5.2.2.1, "Loss of Material Due to Freeze
-Thaw."  Based on its review, the staff concludes that the applicant has adequately evaluated concrete degradation due to freeze
-thaw and no additional plant
-specific program is required for inaccessible areas of Group 6 structures.  (3) Cracking due to expansion and reaction with aggregates, increase in porosity and permeability, and loss of strength due to leaching of calcium hydroxide could occur in below-grade inaccessible reinforced concrete areas of Group 6 structures. In the LRA, the applicant stated that cracking due to expansion and reaction with aggregates is not applicable for both accessible and inaccessible areas of reinforced concrete of Group 6 structures. Aggregate materials were tested in accordance with ASTM C289-65 for potential reactivity. The reinforced concrete for Group 6 structures is designed in accordance with ACI 318-63 and constructed in accordance with ACI 301-66. Cracking due to expansion and reaction with aggregates has not been experienced at Salem.
The staff reviewed LRA Section 3.5.2.2.2.4.3 against the criteria in GALL Report item III.A6-2, which notes that, according to NUREG
-1557, investigations, tests, and petrographic examinations of aggregates performed in accordance with ASTM C29 5-54 can demonstrate that these aggregates do not react within reinforced concrete. The staff's review for cracking due to expansion and reaction with aggregates for inaccessible concrete elements of Groups 1-5 and 7-9 structures is documented in SER Section 3.5.2.2.2, "Aging Management of Inaccessible Areas."
In its review, the staff noted that the LRA discussed ASTM C289-65; however, it made no mention of ASTM C227 or C295 which are discussed in the GALL Report as acceptable methods for identifying aggregates that do not react within concrete. In addition, the LRA did not clearly explain that the concrete was constructed in accordance with the recommendations of ACI 201.2R-77 to demonstrate that an AMP is not required. To address these concerns, by letter dated June 7, 2010, the staff issued RAI 3.5.2.2.1-03. The applicant responded by letter dated July 8, 2010. A discussion of the staff's review of the response, as well as the staff's acceptance of the applicant's evaluation of aging effects due to reactive aggregates, is included in SER Section 3.5.2.2.1, "Cracking Due to Expansion and Reaction with Aggregates.
"  Based on its review, the staff concludes that the aggregates used at Salem are nonreactive. Therefore, cracking due to expansion and reaction with aggregates in below-grade inaccessible concrete areas for Group 6 structures are not aging effects for concrete elements and no additional plant
-specific program is required.
In the LRA, the applicant further stated that increase in porosity and permeability and loss of strength due to leaching of calcium hydroxide of reinforced concrete in accessible and inaccessible areas of water
-control structures (Group 6 structures) subject to a flowing water environment will be managed by the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program as implemented by the applicant's Structures Monitoring Program.
 
Aging Management Review Results 3-472  Leaching is a potential aging mechanism applicable to submerged portions of Group 6 structures exposed to flowing water. However, these areas are accessible for underwater inspection and for inspections when dewatered. The enhanced periodic inspections of the submerged portions of the intake structure of the Structures Monitoring Program will be used to manage this aging effect and mechanism. Leaching is applicable to inaccessible concrete that is buried as it may be subject to a flowing water environment through cracks. Operating experience at Salem has not identified increase in porosity and permeability and loss of strength due to leaching of calcium hydroxide for inaccessible below
-grade portions of Group 6 structures as significant. Inaccessible concrete will be inspected if excavated for any reason, as required by the Structures Monitoring Program.
The staff reviewed LRA Section 3.5.2.2.2.4.3 against the criteria in SRP
-LR Section 3.5.2.2.2.4.3, which states that the GALL Report recommends further evaluation of inaccessible areas if concrete was not constructed in accordance with the recommendations in ACI 201.2R-77. The staff's review for increase in porosity and permeability and loss of strength due to leaching of calcium hydroxide for inaccessible concrete elements of Groups 1-3, 5, and 7
-9 structures is documented in SER Section 3.5.2.2.2, "Aging Management of Inaccessible Areas."
The staff noted that inspections of Group 6 structures are performed under the Structures Monitoring Program, which is consistent with and integrates the elements of the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program.
The staff noted, however, that the LRA did not state that the concrete was constructed in accordance with the recommendations of ACI 201.2R-77 as specified in GALL Report item III.A6
-6. To address this concern, the staff issued RAI 3.5.2.2.1-04, by letter dated June 7, 2010. The applicant responded by letter dated July 8, 2010. A discussion of the staff's review of the response, as well as the staff's acceptance of the applicant's evaluation of aging effects due to leaching of calcium hydroxide, is included in SER Section 3.5.2.2.1, "Increase in Porosity and Permeability Due to Leaching of Calcium Hydroxide
."  Based on its review, the staff concludes that the applicant has demonstrated that the aging effects due to leaching of calcium hydroxide will be adequately managed and no further evaluation is required.
Based on the programs and evaluations identified, the staff concludes that the applicant's programs meet the criteria of SRP
-LR Section 3.5.2.2.2.4. For those line items that apply to LRA Section 3.5.2.2.2.4, the LRA is consistent with the GALL Report and the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
Cracking Due to Stress
-Corrosion Cracking and Loss of Material Due to Pitting and Crevice Corrosion. LRA Section 3.5.2.2.2.5 addresses cracking due to SCC and loss of material due to pitting and crevice corrosion for Groups 7 and 8 stainless steel tank liners. In the LRA, the applicant stated that Salem does not have Groups 7 and 8 stainless steel tank liners and further evaluation for the effects of cracking due to SCC and loss of material due to pitting and crevice corrosion is not applicable.
 
Aging Management Review Results 3-473 The staff reviewed LRA Section 3.5.2.2.2.5 against the criteria in SRP
-LR Section 3.5.2.2.2.5, which states that cracking due to SCC and loss of material due to pitting and crevice corrosion could occur for Groups 7 and 8 stainless steel tank liners exposed to standing water. The GALL Report recommends further evaluation of plant
-specific programs to manage these aging effects. The staff verified that Salem does not have any Group 7 concrete tanks within the scope of license renewal and that steel tanks, including liners, are addressed as part of the mechanical systems. Since there are no components within scope, the staff agrees that this aging effect does not apply.
Aging of Supports Not Covered by the Structures Monitoring Program
. LRA Section 3.5.2.2.2.6 addresses aging of supports not covered by the Structures Monitoring Program.
The staff reviewed LRA Section 3.5.2.2.2.6 against the criteria in SRP
-LR Section 3.5.2.2.2.6.
  (1) Loss of Material Due to General and Pitting Corrosion for Groups B2
-B5 Supports In the LRA, the applicant stated that loss of material due to general and pitting corrosion for Groups B2
-B5 supports is covered under the Structures Monitoring Progra
: m. The staff reviewed LRA Section 3.5.2.2.2.6.1 against the criteria in SRP
-LR Section 3.5.2.2.2.6, which states that further evaluation is necessary only for structure/aging effect combinations not covered by the Structures Monitoring Program.
The staff confirmed that the component support/aging effect combination of loss of material due to general and pitting corrosion for Groups B2
-B5 supports is managed by the Structures Monitoring Program; therefore, further evaluation is not necessary. The staff's review of the Structures Monitoring Program is documented in SER Section 3.0.3.2.15.
  (2) Reduction in Concrete Anchor Capacity Due to Degradation of the Surrounding Concrete for Groups B1-B5 Supports In the LRA, the applicant stated that reduction in anchor capacity due to degradation of the surrounding concrete for Groups 1-5 supports is covered under the Structures Monitoring Program.
The staff reviewed LRA Section 3.5.2.2.2.6.2 against the criteria in SRP
-LR Section 3.5.2.2.2.6.2, which states that further evaluation is necessary only for structure/aging effect combinations not covered by the Structures Monitoring Program.
The staff confirmed that the component support/aging effect combination of reduction in anchor capacity due to degradation of surrounding concrete for Groups 1-5 supports is managed by the Structures Monitoring Program; therefore, further evaluation is not necessary. The staff's review of the Structures Monitoring Program is documented in SER Section 3.0.3.2.15.
  (3) Reduction/Loss of Isolation Function Due to Degradation of Vibration Isolation Elements for Group B4 Supports
 
Aging Management Review Results 3-474  In the LRA, the applicant stated that reduction/loss of isolation function due to degradation of vibration isolation elements for Group B4 supports is covered under the Structures Monitoring Program.
The staff reviewed LRA Section 3.5.2.2.2.6.3 against the criteria in SRP
-LR Section 3.5.2.2.2.6.3, which states that further evaluation is necessary only for structure/aging effect combinations not covered by the Structures Monitoring Program.
The staff confirmed that the reduction/loss of isolation function due to degradation of vibration isolation elements for Group B4 supports is managed by the Structures Monitoring Program; therefore, further evaluation is not necessary. The staff's review of the Structures Monitoring Program is documented in SER Section 3.0.3.2.15.
Based on the programs and evaluations identified, the staff concludes that the applicant's programs meet the criteria of SRP
-LR Section 3.5.2.2.2.6. For those line items that apply to LRA Section 3.5.2.2.2.6, the LRA is consistent with the GALL Report and the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
Cumulative Fatigue Damage Due to Cyclic Loading.
In the LRA, the applicant stated that the CLB contains no fatigue analysis for component support members, anchor bolts, and welds of Groups B1.1, B1.2, and B1.3 component supports. Therefore, a TLAA is not evaluated in accordance with 10 CFR 54.21(c) for these components.
The staff reviewed LRA Section 3.5.2.2.2.7 against the criteria in SRP
-LR Section 3.5.2.2.2.7, which states that fatigue of component support members, anchor bolts, and welds for Groups B1.1, B1.2, and B1.3 component supports is a TLAA as defined in 10 CFR 54.3 only if a CLB fatigue analysis exists. TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c). The staff verified that at Salem, the CLB contains no fatigue analysis for component support members, anchor bolts, and welds of Groups B1.1, B1.2, and B1.3 component supports.
Based on the programs identified, the staff concludes that the applicant's programs meet SRP-LR Section 3.5.2.2.2 criteria. For those line items that apply to LRA Section 3.5.2.2.2, the staff determines that the LRA is consistent with the GALL Report and the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.5.2.2.3  Quality Assurance for Aging Management of Nonsafety
-Related Components SE R Section 3.0.4 documents the staff's evaluation of the applicant's QA program.
3.5.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report In LRA Tables 3.5.2-1 through 3.5.2
-17, 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.
 
Aging Management Review Results 3-475 In LRA Tables 3.5.2-1 through 3.5.2
-17, the applicant indicated, via Notes F through J, that the combination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report. The applicant provided further information about how it will manage the aging effects. Specifically, Note F indicates that the material for the AMR line item component is not evaluated in the GALL Report. Note G indicates that the environment for the AMR line item component and material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR line item component, material, and environment combination is
 
not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the line item component, material, and environment combination is not applicable.
Note J indicates that neither the component nor the material and environment combination for the line item is evaluated in the GALL Report.
LRA Tables 3.5.2
-1, 3.5.2-2, 3.5.2-3, 3.5.2-4, 3.5.2-7, 3.5.2-8, 3.5.2-10, 3.5.2-13, 3.5.2-15, and 3.5.2-16 were revised as a result of the response to RAI B.2.1.9-01, dated July 8, 2010. The revision added AMR items in these tables to reference the applicant's Bolting Integrity Program to manage the aging for bolting AMR items. Existing bolting AMR items which reference other AMPs are used in conjunction with the added bolting AMR items to properly manage aging for bolting components. The staff's evaluation of the applicant's Bolting Integrity Program is documented in SER Section 3.0.3.2.2. The staff notes that the Bolting Integrity Program is supplemented by other AMPs including but not limited to the Structures Monitoring, Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems, External Surfaces Monitoring, and Buried Piping Inspection programs. These other AMPs supplement the Bolting Integrity Program by implementing the requirements of the Bolting Integrity Program for pressure
-retaining bolted joints, component support bolting, and structural bolting within the scope of license renewal. The applicant's action accurately adds the related line items to reference the Bolting Integrity Program; however, the technical evaluations documented in the SER do not change since the management of the aging effect will still be implemented by the AMP identified in conjunction with the Bolting Integrity Program. For component type, material, and environment combinations not evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine whether the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. The staff's evaluation is documented in the following sections.
3.5.2.3.1  Containments, Structures, and Component Supports
-Auxiliary Building
-Summary of Aging Management Evaluation
-LRA Table 3.5.2-1 The staff reviewed LRA Table 3.5.2-1, which summarizes the results of AMR evaluations for the auxiliary building component groups.
In LRA Table 3.5.2-1, the applicant stated that aluminum structural bolting exposed to indoor or outdoor air, carbon and low
-alloy or galvanized steel structural bolting exposed to outdoor air, and stainless steel structural bolting exposed to indoor or outdoor air are being managed for loss of preload due to self
-loosening by the Structures Monitoring Program. The AMR line item cites generic note H indicating that for the line items, the aging effect is not in the GALL Report for this component, material, and environment combination. The AMR line item also cites a plant-specific note stating that based on industry standards and operating experience, age-related loss of preload due to self
-loosening of structural bolting could be caused by vibration, flexing of the joint, or cyclic shear loads that could occur in any environment.
The plant-specific note also states that these causes are considered in the design of structural Aging Management Review Results 3-476 connections and eliminated by initial preload bolt torquing and that loss of preload due to self-loosening of structural bolting is not significant and will not impact structural intended functions. The plant
-specific note further states that loss of preload due to self
-loosening of structural bolts will be managed through the Structures Monitoring Program.
The staff reviewed all AMR result line items in the GALL Report where the component and material is aluminum structural bolting exposed to indoor or outdoor air, carbon and low
-alloy or galvanized steel structural bolting exposed to outdoor air, and stainless steel structural bolting exposed to indoor or outdoor air and confirmed that there are no aging effect entries in the GALL Report for this component, material, and environment combination.
The staff's evaluation of the applicant's Structures Monitoring Program is documented in SER Section 3.0.3.2.15. The staff notes that the Structures Monitoring Program includes visual inspections that are capable of identifying loss of preload in bolted connections by identifying loosening of components which would indicate a loss of preload. The staff also notes that the loss of preload in bolted connections is dependent on such mechanisms as vibration or flexing and is not dependent on the specific air environment to which the bolt is exposed. The staff further notes that the Bolting Integrity Program provides plant instructions for installation and torquing of bolted connections that are based on recommendations in EPRI guidance documents recommended in GALL AMP XI.M18, "Bolting Integrity."  The staff finds the applicant's proposal to manage aging using the Structures Monitoring Program acceptable because the program includes visual inspections which can detect loss of preload and has incorporated industry guidance to prevent loss of preload into its plant instructions that manage loss of preload for all bolting within its scope.
For component type "hatches/plugs," the applicant stated that reinforced concrete encased in steel has no AERMs and does not require an AMP. This item references generic note G and plant-specific Note 3 which states, "Concrete encased in steel is protected from environments that promote age related degradations."  The applicant stated that these components have the intended function of missile barrier, shelter/protection, or structural support.
The staff reviewed the GALL Report and verified that it includes no AMR item for this component, material, and environment combination. The staff finds that since the reinforced concrete is encased in steel and thus protected from the environment, it is not subject to any AERMs. On the basis of its review, the staff concludes that the reinforced concrete encased in steel in the auxiliary building is not subject to any AERMs and that the applicant need not credit any AMP to manage the hatches/plugs.
For component type "penetration seals," the applicant proposed to assign grout to the Structures Monitoring Program to manage the aging effect of cracking/shrinkage in an indoor , outdoor air, or groundwater/soil environment. This item references Note F and plant
-specific Note 5 which states, "Based on industry standards and guidelines, grout is susceptible to cracking due to shrinkage in this environment. However, shrinkage cracking occurs early in plant life and is not expected to be significant for the extended period of operation. Nevertheless, the aging effect will be monitored through the Structures Monitoring Program."  The applicant stated that these components have the intended functions of either structural support, flood barrier, high
-energy line break (HELB)/moderate
-energy line break (MELB) shielding, or shelter/protection and are examined using the Structures Monitoring Program as the primary AMP. The staff's review of the applicant's Structures Monitoring Program is documented in SER Section 3.0.3.2.15. Since the Structures Monitoring Program has been enhanced to inspect penetration seals for indications of deterioration or distress including evidence of leaching, loss of material, cracking, and loss of bond as defined in ACI 201.1R at a Aging Management Review Results 3-477 frequency of 5 years, the staff finds that the applicant has committed to an appropriate AMP for the period of extended operation. The staff finds that the applicant addressed the AERM adequately.
For one component type "penetration seals," the applicant proposed to assign grout to the Structures Monitoring Program to manage the aging effect of loss of material (spalling, scaling), cracking/freeze
-thaw, increase in porosity and permeability, and aggressive chemical attack in an air-outdoor or groundwater/soil environment. This item references Note F and plant-specific Note 6 which states, "The aging effects and aging management program identified for this material/environments combination are consistent with industry guidance."  The applicant stated that these components have the intended functions of flood barrier or shelter/protection and are examined using the Structures Monitoring Program as the primary AMP. The staff's review of the applicant's Structures Monitoring Program is documented in SER Section 3.0.3.2.15. Since the Structures Monitoring Program has been enhanced to inspect penetration seals for indications of deterioration or distress including evidence of leaching, loss of material, cracking, and loss of bond as defined in ACI 201.1R at a frequency of 5 years, the staff finds that the applicant has committed to an appropriate AMP for the period of extended operation. The staff finds that the applicant addressed the AERM adequately.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.5.2.3.2  Containments, Structures, and Component Supports
-Component Supports Commodity Group
-Summary of Aging Management Evaluation
-LRA Table 3.5.2-2 The staff reviewed LRA Table 3.5.2-2, which summarizes the results of AMR evaluations for the component supports commodity group component groups.
In LRA Table 3.5.2
-2, the applicant stated that stainless steel bolting and supports for ASME Class 1, 2, and 3 piping and components exposed to air with steam or water leakage are being managed for loss of material by the ASME Section XI, SubSection IWF Program. The AMR line items cite generic note G. The AMR line items also cite plant
-specific Note 3, indicating that the air with steam or water leakage environment is applicable to local areas within containment that are exposed to potential service water leakage or spray and that plant operating experience has shown that components in this environment exhibit aging similar to those that would be experienced in an outdoor air environment.
The staff reviewed the applicant's ASME Section XI, SubSection IWF Program and its evaluation is documented in SER Section 3.0.3.1.17. The staff finds the applicant's program acceptable to manage aging for these components because it includes periodic visual inspections of ASME Class 1, 2, and 3 bolting and supports to detect loss of material and has incorporated the guidance in EPRI TR
-104213 regarding proper selection, lubrication, and installation of bolting.
In LRA Table 3.5.2-2, the applicant stated that stainless steel bolting and supports for cable trays, conduits, HVAC ducting, tube track, instrument tubing, and non
-ASME piping and components exposed to air with steam or water leakage are being managed for loss of material by the Structures Monitoring Program. The AMR line items cite generic note G. AMR line items Aging Management Review Results 3-478 also cite plant
-specific Note 3, indicating that the air with steam or water leakage environment is applicable to local areas within containment that are exposed to potential service water leakage or spray and that plant operating experience has shown that components in this environment exhibit aging similar to that experienced in an outdoor air environment.
The staff reviewed the applicant's Structures Monitoring Program and its evaluation is documented in SER Section 3.0.3.2.15. The staff finds the applicant's program acceptable to manage aging for these components because it includes periodic visual inspections of bolting and supports to detect loss of material and has incorporated the guidance in EPRI TR
-104213 regarding proper selection, lubrication, and installation of bolting.
In LRA Table 3.5.2-2, the applicant stated that stainless steel bolting and supports for ASME Class 1 piping and components exposed to indoor air are being managed for loss of preload due to self
-loosening by the ASME Section XI, SubSection IWF Program. The AMR line items cite generic note H.
The staff reviewed the applicant's ASME Section XI, SubSection IWF Program and its evaluation is documented in SER Section 3.0.3.1.17. The staff finds the applicant's program acceptable to manage aging for these components because it includes periodic visual inspections of ASME Class 1, 2, and 3 bolting and supports to detect loss of preload and has incorporated the guidance in EPRI TR
-104213 regarding proper selection, lubrication, and installation of bolting to prevent loss of preload.
In LRA Table 3.5.2-2, the applicant stated that stainless steel bolting and supports for cable trays, conduits, HVAC ducting, tube track, instrument tubing, and non
-ASME piping and components exposed to indoor air are being managed for loss of preload due to self
-loosening by the Structures Monitoring Program. The AMR line items cite generic note H.
The staff reviewed the applicant's Structures Monitoring Program and its evaluation is documented in SER Section 3.0.3.2.15. The staff finds the applicant's program acceptable to manage aging for these components because it includes periodic visual inspections of bolting and supports to detect loss of preload and has incorporated the guidance in EPRI TR
-104213 regarding proper selection, lubrication, and installation of bolting to prevent loss of preload.
In LRA Table 3.5.2-2, the applicant stated that carbon or low
-alloy steel supports for ASME Class 1, 2, and 3 piping and components exposed to air with steam or water leakage are being managed for loss of material due to general, pitting, and crevice corrosion by the ASME Section XI, Su bSection IWF Program. The AMR line items cite generic note G. The applicant also stated that carbon and low
-alloy steel supports for ASME Class 2 and 3 piping and components exposed to outdoor air are being managed for loss of preload due to self
-loosening by the ASME Section XI, SubSection IWF Program. The AMR line items cite generic note H.
The staff reviewed the applicant's ASME Section XI, SubSection IWF Program and its evaluation is documented in SER Section 3.0.3.1.17. The staff noted that the ASM E Section XI, SubSection IWF Program manages loss of material and loss of preload by conducting visual inspections to detect degradation before loss of intended functions. The staff finds the applicant's management of carbon or low
-alloy steel supports for ASME Class 1, 2, and 3 piping and components for loss of material and loss of preload acceptable because:  (1) the ASME Section XI, SubSection IWF Program performs visual inspections of supports for loss of preload and loss of material; and (2) the program has incorporated industry guidance on proper selection of bolting materials, lubricants, and installation torque, which is consistent with the Aging Management Review Results 3-479 recommendations in the GALL Report for managing these components for loss of material and loss of preload.
In LRA Table 3.5.2-2, the applicant stated that galvanized, carbon, or low
-alloy steel bolting or supports for cable trays, conduits, HVAC ducts, tube tracks, instrument tubings, non
-ASME piping and components, EDG, HVAC system components, miscellaneous mechanical equipment, platforms, pipe whip restraints, jet impingement shields, masonry walls, other miscellaneous structures, racks, panels, cabinets, and enclosures for electrical equipment or instrumentation exposed to air with steam or water leakage are being managed for loss of material due to general, pitting, and crevice corrosion and exposed to outdoor air are being managed for loss of preload due to self
-loosening by the Structures Monitoring Program. The AMR line items that refer to exposure to air with steam or water leakage cite generic note G. The AMR line items that refer to exposure to outdoor air cite generic note H.
The staff reviewed the applicant's Structures Monitoring Program and its evaluation is documented in SER Section 3.0.3.2.15. The staff noted that the Structures Monitoring Program manages loss of preload and loss of material for bolting by conducting visual inspections of exposed bolting surfaces for loss of material, loose nuts, missing bolts, or other indications. The staff finds the applicant's Structure Monitoring Program acceptable to manage galvanized, carbon, or low
-alloy steel bolting or supports exposed to air with steam or water leakage or outdoor air because:  (1) it includes visual inspections targeted at identifying loss of material and loss of preload and (2) has incorporated industry guidance regarding proper selection of bolting materials, lubricants, and installation torque to prevent and mitigate loss of preload and loss of material, which is consistent with the GAL L Report recommendations for managing these aging effects. For one component type "supports for ASME Class 1 piping and components (high strength steel bolting for NSSS component supports)," the applicant stated that high
-strength stainless steel bolting with yield strength greater than 150 ksi has no AERMs and does not require an AMP. This item references generic note G and plant
-specific Notes 6 and 7. Plant
-specific Note 6 states, "Loss of preload/self loosening is not applicable because the bolts are not required to be preloaded by design. Also, the bolt nuts are either tack welded or lock wired to prevent undesirable self
-loosening."  Note 7 states:
Supports for Unit 2 Steam Generators have high
-strength stainless steel bolts (Carpenter Custom alloy 445 H900), with actual yield strength greater than 150 ksi. The bolts are not preloaded (not torqued) and are not subjected to tensile stress or a corrosive environment. Therefore, cracking due to stress corrosion cracking is not an aging effect requiring management. Also, loss of material due to corrosion is not an aging effect requiring aging management for the bolt material (stainless steel) consistent with NUREG
-1801, Volume 2 Item No. III.B1.1-9. Since the bolting has an intended function associated with structural support for the Unit 2 steam generators, it is unclear to the staff why the stainless steel bolting will not be examined during the period of extended operation under an AMP such as the ASME Section XI, SubSection IWF Program for loss of intended function. By letter dated June 7, 2010, the staff issued RAI 3.5.2.3-01 to address this issue.
 
Aging Management Review Results 3-480 In its response dated July 8, 2010, the applicant stated that the possible AERMs for high-strength bolting exposed to an air environment are loss of material, loss of preload, and SCC. The applicant further explained that according to GALL Report item III.B1.1
-9, stainless steel support members in an indoor uncontrolled air environment are not susceptible to loss of material. The applicant also explained that the bolts are not susceptible to loss of preload because the bolts are not preloaded. Finally, the applicant explained that the bolts are not susceptible to SCC because they are not subject to an environment containing contaminants nor are they subjected to sustained tensile stresses. Therefore, the applicant did not identify any AERMs for the identified bolting. Nevertheless, the ASME Section XI, SubSection IWF Program requires inspection of the steam generator component support bolting. The staff reviewed the applicant's response and found it acceptable because it explained why there are no expected AERMs associated with the Unit 2 steam generator high
-strength stainless steel bolts. In addition, the response explained that the bolts are within the scope of the ASME Section XI, SubSection IWF Program and will be inspected for missing or detached bolts and nuts.
Therefore, the staff finds that the applicant has adequately addressed aging of these components and the staff's concern in RAI 3.5.2.3-01 is resolved.
For component types "supports for ASME Class 1 piping" and "components and supports for ASME Class 2 and 3 piping and components (support members; welds; bolted connections; support anchorage to building structure)," the applicant stated that stainless steel or carbon and low-alloy steel bolting in an air
-indoor or air
-outdoor environment is managed for loss of preload/self
-loosening by the ASME Section XI, SubSection IWF Program. These items reference Note H and plant-specific Notes 1 and 2. Plant
-specific Note 1 states, "ASME Section XI, SubSection IWF is the applicable aging management program for this component."  Plant-specific Note 2 states:
Based on industry standards and operating experience[,] age related loss of preload/self
-loosening of structural bolting could be caused by vibration, flexing of the joint or cyclic shear loads that could occur in any environment. However, these causes are considered in the design of structural connections and eliminated by the initial preload bolt torquing. Thus, loss of preload/self
-loosening of structural bolting is not significant and will not impact structural intended functions. Nevertheless, loss of preload/self
-loosening will be monitored through the applicable aging management program.
The staff's review of the applicant's ASME Section XI, SubSection IWF Program is documented in SER Section 3.0.3.1.17. Since the ASME Section XI, SubSection IWF Program requires periodic visual inspections of ASME Class 1, 2, and 3 piping and component support members for loss of material and loss of mechanical function, including inspection of bolting for loss of material and for loss of preload by inspecting for missing, detached, or loosened bolts and nuts, and relies on design change procedures that are based on EPRI TR
-104213 guidance to ensure proper specification of bolting material, lubricant, and installation torque, the staff finds that the applicant has committed to an appropriate AMP for the period of extended operation. The staff finds that the applicant addressed the AERM adequately.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GAL L Report. The staff finds that the applicant has demonstrated that the effects of aging will be Aging Management Review Results 3-481 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). 3.5.2.3.3  Containments, Structures, and Component Supports
-Containment Structure
- Summary of Aging Management Evaluation
-LRA Table 3.5.2-3 The staff reviewed LRA Table 3.5.2-3, which summarizes the results of AMR evaluations for the containment structure component groups.
In LRA Table 3.5.2-3, the applicant stated that stainless steel insulation jacketing, miscellaneous steel, penetration sleeves, steel components, steel elements, and tube track components exposed to air with steam or water leakage are being managed for loss of material due to pitting and crevice corrosion by the ASME Section XI, SubSection IWE and 10 CFR Part 50, Appendix J programs; Structures Monitoring Program; or Periodic Inspection Program. The AMR line items cite generic note G. The AMR line items also cite plant-specific Note 3, indicating that the air with steam or water leakage environment is applicable to local areas within containment that are exposed to potential service water leakage or spray and that plant operating experience has shown that components in this environment exhibit aging effects similar to those that would be experienced in an outdoor air environment.
The staff reviewed the applicant's ASME Section XI, SubSection IWE; 10 CFR Part 50, Appendix J; Structures Monitoring; and Periodic Inspection programs and its evaluations are documented in SER Sections 3.0.3.2.13, 3.0.3.1.18, 3.0.3.2.15, and 3.0.3.3.2, respectively. The staff finds the applicant's proposed programs acceptable to manage aging for these components because each program or combination of programs includes detailed visual inspections to detect loss of material for stainless steel components.
The staff's evaluation for stainless steel bolting components exposed to indoor air, which are being managed for loss of material by the Bolting Integrity Program and loss of preload due to self-loosening by the ASME Section XI, SubSection IWE and 10 CFR Part 50, Appendix J programs or the Structures Monitoring Program and cite generic note H, is documented in SER Section 3.1.2.3.1.
In LRA Table 3.5.2-3, the applicant stated that stainless, galvanized, carbon, and low
-alloy steel bolting; galvanized steel cable trays, conduits, and tube tracks; carbon steel concrete embedments, pipe whip restraints, jet impingement shields, and all structural steel components; and carbon and galvanized steel panels, racks, cabinets, other enclosures, and miscellaneous components exposed to air with steam or water leakage are being managed for loss of material due to general, pitting, and crevice corrosion by the Structures Monitoring Program. The AMR line items cite generic note G. The applicant also stated that stainless steel bolting exposed to indoor air is being managed for loss of preload due to self-loosening by the Structures Monitoring Program. The AMR line item cites generic note H for this item.
The staff reviewed the applicant's Structures Monitoring Program and its evaluation is documented in SER Section 3.0.3.2.15. The staff noted that the Structures Monitoring Program manages loss of preload or loss of material by conducting visual inspections of exposed bolting surfaces to determine if there is any loss of material, loose nuts, missing bolts, or other indications of aging. The staff finds the applicant's management of the stainless, galvanized, carbon, or low
-alloy steel components exposed to air with steam or water leakage or outdoor air acceptable because:  (1) it includes visual inspections targeted at identifying loss of material and loss of preload and (2) has incorporated industry guidance from EPRI TR
-104213 regarding Aging Management Review Results 3-482 proper selection of bolting materials, lubricants, and installation torque to prevent and mitigate loss of preload and loss of material, which is consistent with the GALL Report recommendations for these aging effects.
In LRA Table 3.5.2-3, the applicant stated that carbon steel penetration sleeves, cap plates, liner, liner anchors, and integral attachments exposed to air with steam or water leakage are being managed for loss of material due to general, pitting, and crevice corrosion by the ASME Section XI, SubSection IWE Program and 10 CFR Part 50, Appendix J Program. The AMR line items cite generic note G.
The staff reviewed all items in the GALL Report where the component is steel containment liner or penetration components and noted that there are GALL Report items for steel penetration sleeves (GALL Report item II.A3
-1) and liner components (GALL Report item II.A2
-11) exposed to indoor air or treated water that recommend managing loss of material using both GALL AMP XI.SI, "ASME Section XI, SubSection IWE," and XI.S4, "10 CFR Part 50, Appendix J."  The staff also notes that air with steam or water leakage is similar to the indoor air or treated water environments discussed in the GALL Report for these components and, therefore, the GALL Report recommended programs are appropriate for these components.
The staff reviewed the applicant's ASME Section XI, SubSection IWE Program and 10 CFR Part 50, Appendix J Program and its evaluations are documented in SER Sections 3.0.3.2.13 and 3.0.3.1.18, respectively. The staff noted that the ASME Section XI, SubSection IWE Program and 10 CFR Part 50, Appendix J Program manage loss of material using visual and volumetric examinations and leak rate testing to ensure no loss of intended functions. The staff finds the ASME Section XI, SubSection IWE Program and 10 CFR Part 50, Appendix J Program acceptable to manage loss of material for these carbon steel components exposed to air with steam or water leakage because they include visual examinations appropriate for these components and are consistent with the GALL Report recommendations for managing this aging effect for these components
. In LRA Table 3.5.2-3, the applicant stated that elastomer moisture barriers (caulking, flashing, and other sealants) and seals and gaskets exposed to air with borated water leakage have an aging effect of loss of sealing due to deterioration that will be managed by a combination of the ASME Section XI, SubSection IWE Program and the 10 CFR Part 50, Appendix J Program. The AMR line item cites generic note G, indicating that the environment is not in the GALL Report for this component and material
. The staff reviewed all AMR results in the GALL Report where the component type is elastomer seals, gaskets, and moisture barriers and confirmed that there are no entries for this component and material combination where the environment is air with borated water leakage.
The staff reviewed the applicant's ASME Section XI, SubSection IWE Program and 10 CFR Part 50, Appendix J Program and its evaluations are documented in SER Sections 3.0.3.2.13 and 3.0.3.1.18, respectively. In its review of the ASME Section XI, SubSection IWE Program and the 10 CFR Part 50, Appendix J Program, the staff noted that visual inspection of moisture barriers are performed in accordance with the requirements of ASME Code Section XI, SubSection IWE and adequate leak tightness of containment seals and gaskets is confirmed with integrated leakage rate tests in accordance with the requirements of 10 CFR 50, Appendix J. The staff noted that this is consistent with the GALL Report recommendations for aging management of elastomer seals, gaskets, and moisture barriers exposed to air
-indoor, uncontrolled, or air
-outdoor (item II.A3
-7). The staff also noted that Aging Management Review Results 3-483 inspections and tests performed to detect age
-related degradation of elastomer seals, gaskets, and moisture barriers exposed to air
-indoor, uncontrolled, or air
-outdoor will be equally capable of detecting age
-related degradation in the same components/material exposed to air with borated water leakage. Because the applicant's proposed AMP for elastomer seals, gaskets, and moisture barriers exposed to air with borated water leakage is capable of detecting age-related degradation for this component, material, and environment combination and implements corrective action in accordance with the requirements of ASME Code Section XI, SubSection IWE and the applicant's corrective action program, the staff finds the applicant's AMR results for this component, material, and environment combination that is not in the GALL Report to be acceptable.
For component type "bolting (containment closure)," the applicant stated that stainless steel bolting in an indoor air environment is managed for loss of preload/self
-loosening by the ASME Section XI, SubSection IWE and 10 CFR Part 50, Appendix J pro grams. This item references Note H and plant
-specific Note 1 which states, "ASME Section XI, SubSection IWE and 10 CFR Part 50, Appendix J are the applicable aging management program[s] for this component
."  The staff agrees that the applicant has committed to an appropriate AMP for the period of extended operation because:
  (1) the ASME Section XI, SubSection IWE Program conducts general and detailed visual examinations and augmented inspections for evidence of aging effects that could affect leak tightness of the containment structure and includes the pressure
-retaining bolting; and (2) the 10 CFR Part 50, Appendix J Program provides for detection of age
-related degradation of components comprising the containment pressure boundary exposed to air environments due to aging effects such as loss of leak tightness, loss of material, or loss of preload in various systems penetrating containment. The staff's review of the applicant's ASME Section XI, SubSection IWE and 10 CFR Part 50, Appendix J programs is documented in SER Sections 3.0.3.2.13 and 3.0.3.1.18, respectively. The staff finds that the applicant addressed the AERM adequately.
For component type "concrete interior," the applicant stated that reinforced concrete in an air
 
with steam or water leakage environment is managed for increase in porosity and permeability, cracking, and loss of material (spalling, scaling) due to aggressive chemical attack. This item references generic note G and plant
-specific Note 3. Plant
-specific Note 3 states, "Air with [a] steam or water leakage environment is applicable to local areas inside containment that are exposed to potential service water leakage or spray. Plant operating experience showed that metal components in this environment exhibit aging effects observed in [an] Air
-Outdoor environment."  The applicant stated that these components have the intended functions of either HELB/MELB shielding, missile barrier, shelter/protection, shielding, or structural support and are examined using the Structures Monitoring Program as the primary AMP. The staff's review of the applicant's Structures Monitoring Program is documented in SER Section 3.0.3.2.15. Since the Structures Monitoring Program inspects concrete based on guidance in ACI 201.1R to detect indications of increase in porosity and permeability, cracking, loss of material (spalling, scaling) due to aggressive chemical attack and cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel, the staff finds that the applicant has committed to an appropriate AMP for the period of extended operation. The staff finds that the applicant addressed the AERM adequately.
For component type "steel components (sump screen)" in an air with steam or water leakage environment, the applicant stated that the stainless steel material is managed for loss of material due to pitting and crevice corrosion. This item references generic note G and plant-specific Note 3 which states, "Air with [a] steam or water leakage environment is applicable to local areas inside containment that are exposed to potential service water leakage Aging Management Review Results 3-484 or spray. Plant operating experience showed that metal components in this environment exhibit aging effects observed in [an] Air
-Outdoor environment."  The applicant stated that this component has an intended function of filter and is examined using the Periodic Inspection Program as the primary AMP. The staff's review of the applicant's Periodic Inspection Program is documented in SER Section 3.0.3.3.2. The Periodic Inspection Program includes provisions for periodic visual inspections of stainless steel components in an air with steam or water leakage environment to detect aging effects of loss of material and reduction of heat transfer.
The applicant noted that the visual inspections are conducted on a 10
-year inspection frequency that has been established based on plant and industry operating experience. The staff agrees that the Periodic Inspection Program is an appropriate AMP to address this AERM; however, since the intended function of the component is to act as a filter and other programs such as GALL AMP XI.M20, "Open
-Cycle Cooling Water System," perform inspections annually and during refueling outages, it is unclear to the staff that an inspection interval of 10 years will be adequate to address the AERM. By letter dated June 7, 2010, the staff issued RAI 3.5.2.3-02 to address this issue.
In its response dated July 8, 2010, the applicant stated that the sump screen was listed as being in an air with steam or water leakage environment based on operating experience with service water leakage inside containment. The applicant further stated that the Periodic Inspection Program includes a procedure to inspect the component after any leakage events. The applicant explained that since the corrosive environment created by possible service water leakage is promptly addressed, no degradation is expected and the 10
-year frequency is adequate.
The staff reviewed the applicant's response and noted that the possible corrosive air with leakage environment is event driven and is promptly addressed after leakage events. The staff noted that the leakage is cleaned up and the affected components are inspected for degradation. Since the components are inspected after events that could lead to corrosive environments, the staff finds the default 10
-year frequency acceptable. Based on its review of the applicant's response, the staff finds that the applicant addressed the AERM adequately and the staff's concern in RAI 3.5.2.3-02 is resolved.
For component type "coating" in either an indoor air or air with borated water environment, the applicant stated that the paint material is managed for cracking, blistering, flaking, peeling, and delamination. This item references generic note J. The applicant stated that this component has an intended function of maintaining adhesion and is examined using the Protective Coating Monitoring and Maintenance Program and the Boric Acid Corrosion Program as the primary AMPs. The staff's evaluations of the applicant's Protective Coating Monitoring and Maintenance Program and the Boric Acid Corrosion Program are documented in SER Sections 3.0.3.1.19 and SER Sections 3.0.3.1.4, respectively. The Protective Coating Monitoring and Maintenance Program manages cracking, blistering, flaking, peeling, and delamination of Service Level I coatings subjected to an indoor air environment in the containment structure. Visual inspections are performed on all accessible areas of t he containment during each refueling outage by qualified individuals knowledgeable in nuclear coatings. More thorough inspections of suspect areas are conducted and, when appropriate, additional testing may be done to characterize the severity of observed deficiencies. The Protective Coating Monitoring and Maintenance Program is consistent with coating monitoring requirements in RG 1.54 (Revision 1) and GL 98
-04 and follows guidelines in ASTM D 5163-05(a). The Boric Acid Corrosion Program manages cracking, blistering, flaking, peeling, and delamination in an environment of air with borated water and includes provisions to identify, inspect, examine, and evaluate leakage, as well as initiate corrective action. Visual Aging Management Review Results 3-485 examinations are conducted in locations where leakage is detected, as well as adjacent locations that may be affected by the observed leakage. The examinations inside containment are performed during each refueling outage in accordance with the requirements of GL 88-05. The staff finds that the applicant has committed to an appropriate AMP for the period of extended operation because:
  (1) the Protective Coating Monitoring and Maintenance Program is used to verify coating adhesion and thus prevent blockage of the suction strainers, and (2) th e Boric Acid Corrosion Program is used to manage loss of material due to boric acid corrosion. The staff finds that the applicant addressed the AERM adequately.
For component type "insulation (liner plate)" in an indoor air environment, the applicant stated that asbestos having an intended function of insulation does not have AERMs. This item references generic note J and plant
-specific Note 14 which states:
Asbestos is a mineral fiber. The asbestos material located indoors and subject to an air-indoor environment is not subject to significant aging effects. Asbestos materials do not experience aging effects unless exposed to temperatures, radiation, or chemicals capable of attacking specific inorganic chemical composition. Asbestos materials are selected for compatibility with the environment during design. Asbestos material in this non
-aggressive air environment is not expected to experience significant aging effects. This is consistent with plant operating experience.
The LRA states that the lower portion of the containment steel liner is largely covered by the liner insulation and stainless steel lagging and that in 2008, four insulation panels and lagging were removed in Unit 1 to permit inspection of the steel liner plate and moisture barrier which revealed no degradation of moisture barrier or significant liner corrosion. Since the LRA states that insulation and lagging will be removed at sample locations and the liner will be examined in accordance with ASME Code Section XI, SubSectio n IWE requirements both prior to the period of extended operation and every 10 years thereafter, the staff finds that potential degradation of the insulation would be identified in conjunction with the planned ASME Code Section XI, SubSection IWE inspections of the liner plate and a separate AMP is not required.
For component type "moisture barrier (caulking, flashing, and other sealants)" in an air with borated water environment, the applicant stated that elastomers having an intended function of water-retaining boundary are managed for loss of sealing/deterioration of seals, gaskets, and moisture barriers (caulking, flashing, and gaskets) by the ASME Section XI, SubSection IWE Program. This item references generic note G. The staff's evaluation of the applicant's ASME Section XI, SubSection IWE Program is documented in SER Section 3.0.3.2.13. The staff finds that the applicant has committed to an appropriate AMP for the period of extended operation because:  (1) the ASME Section XI, SubSection IWE Program performs visual inspections for evidence of aging effects that could affect loss of sealing of accessible portions of the moisture barrier, and (2) the program has been enhanced to require 100 percent visual inspection of the moisture barrier at the junction between the containment concrete floor and the containment liner to the extent practical both prior to the period of extended operation and every 10 years thereafter (Commitment No.28). The staff finds that the applicant addressed the AERM adequatel y. For component type "piles (heavy equipment platform foundation)," the applicant stated that concrete encased in steel and having an intended function of structural support does not have AERMs. This item references generic note G and plant
-specific Note 8 which states, "Concrete Aging Management Review Results 3-486 encased in steel is protected from environments that promote age related degradations."  The LRA states that degradation of piles or foundation mats will manifest in settlement distortion or cracking and accessible concrete examinations will detect cracks and distortion of the structures. Studies have shown that steel piles driven into undisturbed natural soil are not appreciably affected by corrosion due to the oxygen deficiency in soil at a few feet below grade. Piles driven into disturbed soil have been shown to experience only minor to moderate corrosion. In either case, the observed loss of material due to corrosion was not considered significant enough to impact the intended function of the piles, which is consistent with NUREG-1557. Since the concrete is encased in steel and, therefore, in a protected environment and containment
-related structures are monitored under the Structures Monitoring Program for cracks and distortion due to increased stress levels from settlement, the staff finds that a separate AMP for concrete piles encased in steel is not required. The staff's review of the Structures Monitoring Program is documented in SER Section 3.0.3.2.15. The staff finds the applicant addressed the AERM adequately.
For component type "transfer tube bellows (excludes containment penetration bellows)" in a treated borated water environment, the applicant stated stainless steel having an intended function of water
-retaining boundary is managed for cumulative fatigue damage/fatigue by TLAA. This item references generic note G and plant
-specific Note 15 which states, "The TLAA designation in the Aging Management Program column indicates fatigue of this component is evaluated in Section 4.5."  LRA Section 3.5.2.2.1.6 states tha t a TLAA evaluation for the transfer tube bellows was performed. The stainless steel transfer tube bellows are not part of the containment penetration bellows and are not part of the containment pressure boundary, but are a water-retaining boundary associated with the reactor cavity in the containment and the transfer pool in the fuel handling building. The TLAA evaluation shows that the projected number of cycles for 60 years is less than the design cycles. Thus, cracking of transfer tube bellows due to cyclic loading is not expected to occur through the period of extended operation. The TLAA is evaluated in accordance with 10 CFR 54.21(c). Evaluation of this TLAA is discussed in SER Section 4.5, "Fuel Transfer Tube Bellows Design Cycles."
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.5.2.3.4  Containments, Structures, and Component Supports
-Fire Pump House
-Summary of Aging Management Evaluation
-LRA Table 3.5.2-4 The staff reviewed LRA Table 3.5.2-4, which summarizes the results of AMR evaluations for the fire pump house component groups.
The staff's evaluation for stainless steel bolting components exposed to indoor air, which are being managed for loss of material by the Bolting Integrity Program and loss of preload due to self-loosening by the ASME Section XI, SubSection IWE and 10 CFR Part 50, Appendix J programs, or the Structures Monitoring Program and cite generic note H, is documented in SER Section 3.1.2.3.1.
In LRA Tables 3.5.2
-4, 3.5.2-7, 3.5.2-10, 3.5.2-13, and 3.5.2
-16, the applicant stated that aluminum bolting exposed to either indoor or outdoor air is being managed for loss of preload due to self
-loosening by the Structures Monitoring Program. The AMR line items cite generic Aging Management Review Results 3-487 note H for this item, indicating that this aging effect is not in the GALL Report for this component, material, and environment combination.
The staff reviewed the associated line items in the LRA and confirmed that the applicant has identified the correct aging effects for this component, material, and environment combination because aluminum bolting will have comparable loss of preload as other bolting material. The staff's evaluation of the applicant's Structures Monitoring Program is documented in SER Section 3.0.3.2.15. The staff finds the applicant's proposal to manage aging using the above program acceptable because the Structures Monitoring Program uses guidance from EPRI TR-104213 for ensuring that loss of preload is appropriately managed, which is consistent with the GALL Report for management of bolting.
The staff's evaluation for grout penetration seals exposed to an indoor or outdoor air environment, which are being managed for cracking or loss of material by the Structures Monitoring Program with generic note F, is documented in SER Section 3.5.2.3.1.
The staff's evaluation for interior concrete of concrete filled steel piles, with no aging effect an d no credited AMP and referencing generic note G, is documented in SER Section 3.5.2.3.3.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.5.2.3.5  Containments, Structures, and Component Supports
-Fuel Handling Building-Summary of Aging Management Evaluation
-LRA Table 3.5.2-5 The staff reviewed LRA Table 3.5.2-5, which summarizes the results of AMR evaluations for the fuel handling building component groups.
In LRA Table 3.5.2-5, the applicant stated that the stainless steel transfer tube penetration bellows exposed to treated borated water are being managed for cumulative fatigue damage by a TLAA. The AMR line item cites generic note G. TLAAs are evaluated in accordance with 10 CFR 54.21(c)(1) and the staff's evaluation of the TLAA for this item is documented in SER Section 4.5. In LRA Table 3.5.2-5, the applicant stated that stainless steel penetration bellows components exposed to groundwater or soil are being managed for cumulative fatigue damage by a TLAA. The AMR line item cites generic note G. TLAAs are evaluated in accordance with 10 CFR 54.21(c)(1) and the staff's evaluation of the TLAA for this item is documented in SER Section 4.5. In LRA Table 3.5.2-5, the applicant stated that stainless steel transfer tube penetration bellows exposed to groundwater or soil are being managed for loss of material due to pitting, crevice, and microbiologically
-influenced corrosion by the Buried Non
-Steel Piping Inspection Program. The AMR line items cite generic note H.
The staff reviewed the applicant's Buried Non
-Steel Piping Inspection Program and its evaluation is documented in SER Section 3.0.3.3.4. The staff finds the applicant's program acceptable to manage aging for these components because it includes focused visual Aging Management Review Results 3-488 inspections for loss of material when the components are excavated for any reason or at least one inspection will be performed within the 10 years prior to the period of extended operation and one during the first 10 years of extended operation.
For component type "penetration sleeves," the applicant proposed to assign carbon steel to the Periodic Inspection Program to manage the aging effect of loss of material due to pitting and crevice corrosion in a treated borated water environment. This item references generic note G. The applicant stated that this component has the intended function of water
-retaining boundary. The Periodic Inspection Program includes provisions for periodic visual inspections of stainless steel, aluminum, copper alloy, and elastomer components in a treated borated water environment to detect aging effects of loss of material and reduction of heat transfer. The applicant noted that the visual inspections are conducted on a 10
-year inspection frequency that has been established based on plant and industry operating experience. The staff's evaluation of the applicant's Periodic Inspection Program is documented in SER Section 3.0.3.3.2. During the staff's review of the Periodic Inspection Program, it was noted that carbon steel components do not appear to be addressed by this AMP and a 10
-year inspection frequency is used. The staff is unclear how the Periodic Inspection Program will be used to address the AERM and that the inspection interval is frequent enough to detect degradation in a timely manner during the period of extended operation. By letter dated June 7, 2010, the staff issued RAI 3.5.2.3-03 to address this issue. In its response dated July 8, 2010, the applicant explained that the penetration sleeves are the carbon steel sleeves for the fuel transfer tubes, where the sleeves extend into the fuel transfer pools. The applicant further explained that the sleeves are coated with a three part epoxy system which is resistant to borated water based on testing of similar epoxy systems by the same manufacturer. The applicant also stated that based upon data in EPRI NP
-5769, "Degradation and Failure of Bolting in Nuclear Power Plants," the corrosion rate of carbon steel in borated water is 0.02 inch per year or less. The applicant further stated that the sleeve is nominally 1 inch thick. Based upon these facts, the applicant concluded the 10
-year inspection frequency was adequate.
The staff reviewed the applicant's response and found it acceptable. The staff noted that the components are coated by an epoxy system. The staff also noted that corrosion of the penetration sleeves would be visible as a rust product which would be identified during a visual inspection. The staff's review did not identify any plant
-specific operating experience that would indicate a 10
-year inspection interval was inadequate. In addition, the components are included within the scope of the One-Time Inspection and Water Chemistry programs which provide additional assurance that any degradation would be captured and identified in a timely manner. Since the Periodic Inspection Program includes visual inspections of the penetration sleeves, conducted with an acceptable frequency, the staff finds that the applicant addressed the AERM adequately and the staff's concern in RAI 3.5.2.3-03 is resolved.
For component type "steel components (leak chase system)," the applicant proposed to assign carbon steel to either the One
-Time Inspection Program or Water Chemistry Program to manage the aging effect of loss of material due to general, pitting, and crevice corrosion in a treated borated water (internal or external) environment. This item references generic note G and plant-specific Note 4 which states:
Plant operating experience showed that treated borated water leakage through indications in the liner plate welds could overflow the leak chase channels if the drain lines are clogged and come into contact with reinforced concrete, exterior Aging Management Review Results 3-489 surfaces of the stainless steel liner, and the leak chase channel system. The leak chase channels drain lines will be monitored for blockage and cleared as required to ensure proper drainage is maintained.
The applicant stated that this component has the intended function of direct flow. The staff's evaluations of the applicant's One-Time Inspection Program and Water Chemistry Program are documented in SER Sections 3.0.3.1.11 and 3.0.3.1.2, respectively. The Water Chemistry Program manages the effects of cracking, loss of material, reduction of neutron
-absorbing capacity, and reduction of heat transfer for RCS and related auxiliary systems containing treated water, reactor coolant, treated borated water, and steam, including the primary side of steam generators. This program includes periodic sampling of primary and secondary water for the known detrimental contaminants (e.g., chlorides, fluorides, dissolved oxygen, and sulfates). The Water Chemistry Program does not provide for detection of aging effects. The One
-Time Inspection Program is used to confirm the effectiveness of the Water Chemistry Program to manage loss of material, cracking, and reduction of heat transfer aging effects of steel in treated borated water. The One
-Time Inspection Program is a condition monitoring program for identification of aging effects and evaluation of the need for follow
-up examinations to monitor progression of age
-related degradation with inspections scheduled within 10 years prior to the period of extended operation. In the LRA, it notes that the spent fuel pools at Salem have experienced leakage of borated water that has migrated through small cracks in the concrete to reach the seismic gap between the containment structure and fuel handling building. Materials such as boric acid and minerals have accumulated in the leak collection and detection system that restricted normal drainage of fluid. Borated water has accumulated between the liner and concrete and migrated to other locations through penetrations, construction joints, and cracks. The seismic gap was confirmed to contain water with radionuclides characteristic of the spent fuel pool water and leakage into the seismic gap has continued. Leakage into the telltale drains is occurring at a rate of about 100 gallons per day. Based on operating experience provided in the LRA, it is unclear to the staff how this AERM will be adequately addressed through the One-Time Inspection and Water Chemistry programs. By letter dated June 7, 2010, the staff issued RAI 3.5.2.3-04 to address this issue.
In its response dated July 8, 2010, the applicant stated that this component is also monitored by the Structures Monitoring Program. The Structures Monitoring Program is being enhanced to ensure that the intended function of directing flow is maintained by monitoring the telltale leakage and inspecting the system to ensure no blockage. This inspection will be performed on an interval not to exceed 18 months. The applicant explained that this inspection would be capable of detecting a buildup of corrosion products. The applicant also explained that based upon data in EPRI NP
-5769, "Degradation and Failure of Bolting in Nuclear Power Plants," the corrosion rate of carbon steel in borated water is 0.02 inch per year or less. The applicant stated that the proposed AMPs, including the 18 month frequency inspections conducted by the Structures Monitoring Program, are adequate.
The staff reviewed the applicant's response and found it acceptable. Although the staff does not necessarily agree with the corrosion rate quoted by the applicant, the staff notes that the applicant has enhanced the Structures Monitoring Program to monitor the telltale leakage and to inspect the system on an 18 month frequency. These activities provide reasonable assurance that degradation of the leak chase system will be detected prior to loss of intended function.
The staff's evaluation of the applicant's Structures Monitoring Program is documented in SER Section 3.0.3.2.15. Since the applicant has committed to inspections of the leak chase system, the staff finds that the applicant addressed the AERM adequately and the staff's concern in RAI 3.5.2.3-04 is resolved.
 
Aging Management Review Results 3-490 The staff's evaluation for grout penetration seals exposed to an indoor or outdoor airenvironment, which are being managed for cracking or loss of material by the Structures Monitoring Program with generic note F, is documented in SER Section 3.5.2.3.1.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.5.2.3.6  Containments, Structures, and Component Supports
-Office Buildings
-Summary of Aging Management Evaluati on-LRA Table 3.5.2-6 The staff reviewed LRA Table 3.5.2-6, which summarizes the results of AMR evaluations for the office buildings component groups.
In LRA Tables 3.5.2
-6, 3.5.2-10, 3.5.2-12, 3.5.2-13, 3.5.2-15, 3.5.2-16, and 3.5.2
-17, the applicant stated that galvanized, carbon, or low
-alloy steel bolting exposed to outdoor air is being managed for loss of preload due to self
-loosening by the Structures Monitoring Program. The AMR line items cite generic note H.
The staff reviewed the applicant's Structures Monitoring Program and its evaluation is documented in SER Section 3.0.3.2.15. The staff noted that the Structures Monitoring Program manages loss of preload or loss of material by conducting visual inspections of exposed bolting surfaces to determine if there is any loss of material, loose nuts, missing bolts, or other indications of aging. The staff finds the applicant's program acceptable to manage aging for these components because:  (1) it includes visual inspections targeted at identifying loss of material and loss of preload and (2) has incorporated industry guidance from EPRI TR
-104213 regarding proper selection of bolting materials, lubricants, and installation torque in order to prevent and mitigate loss of preload, which is consistent with the GALL Report recommendations for managing this aging effect.
The staff's evaluation for interior concrete of concrete filled steel piles, with no aging effect and no credited AMP and referencing generic note G, is documented in SER Section 3.5.2.3.3.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.5.2.3.7  Containments, Structures, and Component Supports
-Penetration Areas-Summary of Aging Management Evaluation
-LRA Table 3.5.2-7 The staff reviewed LRA Table 3.5.2-7, which summarizes the results of AMR evaluations for the penetration areas component groups.
The staff's evaluation for aluminum bolting exposed to indoor and outdoor air, which is being managed for loss of preload by the Structures Monitoring Program with generic note H, is documented in SER Section 3.5.2.3.4.
 
Aging Management Review Results 3-491 The staff's evaluation for interior concrete of concrete filled steel hatches/plugs, with no aging effect and no credited AMP and referencing generic note G, is documented in SER Section 3.5.2.3.1.
3.5.2.3.8  Containments, Structures, and Component Supports
-Pipe Tunnel
-Summary of Aging Management Evaluation
-LRA Table 3.5.2-8 The staff reviewed LR A Table 3.5.2-8, which summarizes the results of AMR evaluations for the pipe tunnel component groups.
In LRA Table 3.5.2-8, the applicant stated that stainless steel structural bolting components exposed to outdoor air are not being managed for loss of preload due to self
-loosening. The AMR line item cites generic note G. The AMR line item also cites plant
-specific Note 2, which indicates that no AMP is required because the nuts on the bolting are tack welded.
The staff finds that the applicant's determination that no AMP is required to manage loss of preload for this component acceptable because bolts with tack welded nuts would not be expected to experience loss of preload and the components are being managed for loss of material in another line.
By letter dated June 7, 2010, the staff issued RAI 3.5.2.3-05 regarding the lack of an AMP for this component. This RAI was issued in error. The topic was discussed during a conference with the applicant on May 19, 2010, during which the applicant explained
 
that the bolts were tack welded and the staff agreed no AMP was necessary and, therefore, no RAI was necessary.
The staff's evaluation for grout penetration seals exposed to an air
-indoor, air
-outdoor, or groundwater/soil environment, which are being managed for cracking or loss of material by the Structures Monitoring Program with generic note F, is documented in SER Section 3.5.2.3.1.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.5.2.3.9  Containments, Structures, and Component Supports
-Piping and Component Insulation Commodity Group
-Summary of Aging Management Evaluation
-LRA Table 3.5.2-9 The staff reviewed LRA Table 3.5.2-9, which summarizes the results of AMR evaluations for the piping and component insulation commodity group component groups.
For component type "insulation," the applicant stated that "Min
-K," calcium silicate, ceramic fiber, fiberglass, and NUKON in an air
-indoor, air
-outdoor, or air with borated water leakage environment having an intended function of thermal insulation does not have AERMs and does not require an AMP. The applicant also stated for component type "insulation jacketing (includes wire mesh, straps, clips)," the fiberglass blanket in an air
-indoor or air with borated water leakage environment having an intended function of either shelter/protection or structural support also does not have AERMs. Both of these items reference generic note J and plant-specific Note 1 which states, "Based on plant operating experience, there are no aging effects requiring management for this material and environment combination."  The LRA also states that the purpose of piping and component insulation is to improve thermal efficiency, minimize heat loads on the HVAC systems, provide for personnel protection, prevent freezing of Aging Management Review Results 3-492 heat traced piping, or protect against sweating of cold piping and components. Insulation located in areas with safety
-related equipment is designed to protect nearby safety
-related SSC equipment from overheating and maintain its structural integrity during postulated design
-basis seismic events. Insulation within the containment structure is required to maintain its integrity to prevent exceeding the analyzed debris limit for the containment sump screens. The insulation and insulation jacketing (includes wire mesh, straps, clips) perform an intended function and are within the scope of license renewal under 10 CFR 54.4(a)(2). The staff reviewed the GALL Report and verified that it includes no AMR item for this component, material, and environment combination. Since the piping and component insulation commodity group is not classified as a safety-related commodity and the thermal insulation is typically passive and long
-lived, the staff concludes there are no applicable AERMs for the materials or environments identified in the table and that the applicant need not credit an AMP.
In LRA Table 3.5.2-9, the applicant stated that stainless steel insulation and insulation jacketing components exposed to air with steam or water leakage are being managed for loss of material due to pitting and crevice corrosion by the Periodic Inspection Program. The AMR line items cite generic note G.
The staff's evaluation of the applicant's Periodic Inspection Program is documented in SER Section 3.0.3.3.2. The staff finds the applicant's program acceptable to manage aging for these components because it includes periodic visual inspections to detect loss of material, which is appropriate for these components.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.5.2.3.10 Containments, Structures, and Component Supports
-Station Blackout Compressor Building-Summary of Aging Management Evaluation
-LRA Table 3.5.2-10 The staff reviewed LRA Table 3.5.2-10, which summarizes the results of AMR evaluations for the SBO compressor building component groups.
The staff's evaluation for galvanized carbon or low
-alloy steel bolting exposed to outdoor air, which is being managed for loss of preload due to self
-loosening by the Structures Monitoring Program and with generic note H, is documented in SER Section 3.5.2.3.6.
The staff's evaluation for aluminum bolting exposed to indoor and outdoor air, which is being managed for loss of preload by the Structures Monitoring Program with generic note H, is documented in SER Section 3.5.2.3.4.
3.5.2.3.11 Containments, Structures, and Component Supports
-Service Building
-Summary of Aging Management Evaluation
-LRA Table 3.5.2-11 The staff reviewed LRA Table 3.5.2-11, which summarizes the results of AMR evaluations for the service building component groups.
The staff's evaluation for interior concrete of concrete filled steel piles, with no aging effect and no credited AMP and referencing generic note G, is documented in SER Section 3.5.2.3.3.
 
Aging Management Review Results 3-493 3.5.2.3.12 Containments, Structures, and Component Supports
-Service Water Accumulator Enclosures
-Summary of Aging Management Evaluation
-LRA Table 3.5.2-12 The staff reviewed LRA Table 3.5.2-12, which summarizes the results of AMR evaluations for the service water accumulator enclosures component groups.
The staff's evaluation for galvanized, carbon, or low
-alloy steel bolting exposed to outdoor air, which is being managed for loss of preload due to self
-loosening by the Structures Monitoring Program with generic note H, is documented in SER Section 3.5.2.3.6.
3.5.2.3.13 Containments, Structures, and Component Supports
-Service Water Intake-Summary of Aging Management Evaluation
-LRA Table 3.5.2-13 The staff reviewed LRA Table 3.5.2-13, which summarizes the results of AMR evaluations for the service water intake component groups.
In LRA Table 3.5.2-13, for component type "ice barrier/marine dock bumper" in either an air-outdoor or water flowing environment, the applicant stated that the treated wood is managed for change in material properties, loss of material due to insect damage, and moisture damage by the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program. This item references generic note J. The LRA states that these components have the intended function of shelter/protection and are in the form of steel shapes and treated wood that are designed such that surface ice jams will not damage the service water intake structure. The design of the ice barriers also includes marine dock bumpers. The LRA also states that the applicant's RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program is implemented through the Structures Monitoring Program. The staff's evaluations of the applicant's RG 1.127, Inspection of Wate r-Control Structures Associated with Nuclear Power Plants and Structures Monitoring programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.2.15, respectively. The staff agrees that the applicant has committed to an appropriate AMP for the period of extended operation because the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program:
  (1) has been enhanced to monitor change in material properties and loss of material due to insect damage and moisture damage and (2) is implemented through the Structures Monitoring Program, which conducts visual inspections on a frequency not to exceed 5 years. The staff finds that the applicant addressed the AERM adequately.
In LRA Tables 3.5.2
-13 and 3.5.2
-15, the applicant stated that stainless steel structural bolting exposed to raw water, indoor air, and outdoor air is being managed for loss of preload due to self-loosening by the Structures Monitoring Program. The AMR line items cite generic note H.
The staff reviewed the applicant's Structures Monitoring Program and its evaluation is documented in SER Section 3.0.3.2.15. The staff finds the applicant's program acceptable to manage aging for these components because:  (1) it includes periodic visual inspections for missing or loose bolts in order to detect loss of preload and (2) has incorporated the guidance in EPRI TR-104213 regarding proper selection, lubrication, and installation of bolting in order to prevent loss of preload from occurring.
The staff's evaluation for galvanized, carbon, or low
-alloy steel bolting exposed to outdoor air, which is being managed for loss of preload due to self
-loosening by the Structures Monitoring Program with generic note H, is documented in SER Section 3.5.2.3.6.
 
Aging Management Review Results 3-4 94 The staff's evaluation for aluminum bolting exposed to indoor and outdoor air, which is being managed for loss of preload by the Structures Monitoring Program with generic note H, is documented in SER Section 3.5.2.3.4.
For component type "bolting (structural)" in a raw water environment, the applicant stated that stainless steel bolting having an intended function of structural support is managed for loss of preload due to self
-loosening by the Structures Monitoring Program Program. This item references generic note G and plant
-specific Note 1 which states:
Based on industry standards and operating experience[,] age related loss of preload/self
-loosening of structural bolting could be caused by vibration, flexing of the joint or cyclic shear loads that could occur in any environment. However, these causes are considered in the design of structural connections and eliminated by the initial preload bolt torquing. Thus, loss of preload/
self-loosening of structural bolting is not significant and will not impact structural intended functions. Nevertheless, loss of preload/self
-loosening will be monitored through the Structures Monitoring Program.
The staff's evaluation of the applicant's Structures Monitoring Program is documented in SER Section 3.0.3.2.15. T he staff agrees that the applicant has committed to an appropriate AMP for the period of extended operation because:  (1) the Structures Monitoring Program monitors exposed surfaces of bolting for loss of material due to corrosion, loose nuts, missing bolts, or other indications of loss of preload; and (2) the program incorporates procedures based on EPRI TR-104213, "Bolted Joint Maintenance and Applications Guide," to ensure proper specification of bolting material, lubricant, and installation torque. The staff finds that the applicant addressed the AERM adequately.
For component types "concrete (below grade exterior)" and "concrete foundation" in a groundwater/soil environment, the applicant stated that the reinforced concrete having the intended function of either flood barrier, shelter/protection, or structural support is managed for cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel by the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants. This item references Note H and plant
-specific Note 3 which states, "The aging effects and Aging Management Program identified for this material/environments combination are consistent with industry guidance."  The LRA states that the applicant's Structures Monitoring Program is used to implement the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program.
The staff's evaluations of the applicant's RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants and Structures Monitoring programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.2.15, respectively. The staff agrees that the applicant has committed to an appropriate AMP for the period of extended operation because the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program:
  (1) has been enhanced to visually inspect water
-control structures; (2) is implemented through the Structures Monitoring Program, which conducts visual inspections on a frequency not to exceed 5 years; and (3) is based on guidance provided in RG 1.127 and ACI 349.3R. The staff finds that the applicant addressed the AERM adequately.
For component type "concrete (interior)" in a water flowing environment, the applicant stated that the reinforced concrete having an intended function of either direct flow or structural support is managed for cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of Aging Management Review Results 3-495 embedded steel and increase in porosity and permeability, cracking, and loss of material (spalling, scaling) due to aggressive chemical attack by the RG 1.127 Inspection of Water-Control Structures Associated with Nuclear Power Plants Program. This item references Note H and plant
-specific Note 3 which states, "The aging effects and Aging Management Program identified for this material/environments combination are consistent with industry guidance."  The LRA states that the applicant's Structures Monitoring Program is used to implement the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program.
The staff's evaluations of the applicant's RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants and the Structures Monitoring programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.2.15, respectively. The staff agrees that the applicant has committed to an appropriate AMP for the period of extended operation because the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program:  (1) has been enhanced to visually inspect water
-control structures; (2) is implemented through the Structures Monitoring Program, which conducts visual inspections on a frequency not to exceed 5 years; and (3) is based on guidance provided in RG 1.1.27 and ACI 349.3R. The staff finds that the applicant addressed the AERM adequately.
For component type "penetration seals," the applicant proposed to assign grout to the Structures Monitoring Program to manage the aging effect of cracking and shrinkage in an air-indoor, air
-outdoor, or water flowing environment. This item references Note F and plant-specific Note 5 which states, "Based on industry standards and guidelines, grout is susceptible to cracking due to shrinkage in this environment. However, shrinkage cracking occurs early in plant life and is not expected to be significant for the extended period of operation. Nevertheless, the aging effect will be monitored through the Structures Monitoring Program."  The applicant stated that these components have the intended function of flood barrier and are examined using the Structures Monitoring Program as the primary AMP. The staff's evaluation of the applicant's Structures Monitoring Program is documented in SER Section 3.0.3.2.15. Since the Structures Monitoring Program has been enhanced to inspect penetration seals for indications of concrete deterioration or distress including evidence of leaching, loss of material, cracking, and loss of bond as defined in ACI 201.1R at a frequency of 5 years, the staff agrees that the applicant has committed to an appropriate AMP for the period of extended operation. The staff finds that the applicant addressed the AERM adequately.
For component type "penetration seals," the applicant proposed to assign grout to the Structures Monitoring Program to manage the aging effect of loss of material (spalling, scaling), cracking due to freeze
-thaw, increase in porosity and permeability, and aggressive chemical attack in either an air
-outdoor, groundwater/soil, or water flowing environment. This item references Note F and plant
-specific Note 3 which states, "The aging effects and aging management program identified for this material/environments combination are consistent with industry guidance."  The applicant stated that these components have an intended function of flood barrier and are examined using the Structures Monitoring Program as the primary AMP. The staff's evaluation of the applicant's Structures Monitoring Program is documented in SER Section 3.0.3.2.15. Since the Structures Monitoring Program has been enhanced to inspect penetration seals for indications of concrete deterioration or distress including evidence of leaching, loss of material, cracking, and loss of bond as defined in ACI 201.1R at a frequency of 5 years, the staff agrees that the applicant has committed to an appropriate AMP for the period of extended operation. The staff finds that the applicant addressed the AERM adequately.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Aging Management Review Results 3-496 Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.5.2.3.14 Containments, Structures, and Component Supports
-Shoreline Protection and Dike-Summary of Aging Management Evaluation
-LRA Table 3.5.2-14 The staff reviewed LRA Table 3.5.2-14, which summarizes the results of AMR evaluations for the shoreline protection and dike component groups.
For component type "earthen water
-control structures/embankments (dikes)" having an intended function of flood barrier, the applicant proposed to assign soil, rip
-rap, sand, and gravel to the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program to manage the aging effects of loss of material, loss of form due to erosion, settlement, sedimentation, frost action, waves, currents, surface runoff, and seepage in an air
-outdoor environment. This item references generic note G and plant
-specific Note 2 which states, "Based on industry standards and guidelines, earthen water
-control structures are susceptible to loss of material and loss of form in [an] air
-outdoor environment."  The LRA also states that the applicant's RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program is implemented through the Structures Monitoring Program. The staff's evaluations of the applicant's RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants and Structures Monitoring programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.2.17, respectively. The staff agrees that the applicant has committed to an appropriate AMP for the period of extended operation because the RG 1.127, Inspection of Water
-Control Structures Associated with Nuclear Power Plants Program:  (1) is based on guidance provided in RG 1.127, which addresses aging effects noted above; and (2) is implemented through the Structures Monitoring Program, which conducts visual inspections on a frequency not to exceed 5 years. The staff finds that the applicant addressed the AERM adequately.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.5.2.3.15 Containments, Structures, and Component Supports
-Switchyard
-Summary of Aging Management Evaluation
-LRA Table 3.5.2-15 The staff reviewed LRA Table 3.5.2-15, which summarizes the results of AMR evaluations for the switchyard component groups.
The staff's evaluation for stainless steel structural bolting exposed to raw water, indoor air, and outdoor air, which is being managed for loss of preload due to self
-loosening by the Structures Monitoring Program with generic note H, is documented in SER Section 3.5.2.3.13.
The staff's evaluation for galvanized, carbon, or low
-alloy steel bolting exposed to outdoor air, which is being managed for loss of preload due to self
-loosening by the Structures Monitoring Program with generic note H, is documented in SE R Section 3.5.2.3.6.
 
Aging Management Review Results 3-497 In LRA Table 3.5.2-15, the applicant stated that polyvinylchloride (PVC) conduit exposed to concrete has no AERM and that for this component, material, and environment combination, no AMP is needed. The AMR line items cite generic note J, indicating that neither the component nor the material and environment combination is evaluated in the GALL Report.
The staff reviewed the GALL Report and confirmed that neither the conduit nor PVC is included therein. This review confirmed that the applicant's use of generic note J is acceptable.
For these AMR results, the applicant also cited plant
-specific Note 3, stating that the PVC is encased in concrete and has no aging effects for the identified environment. The staff notes that given the component's switchyard location with potential proximity to high
-voltage equipment or exposure to sunlight, PVC components could be susceptible to known stressors such as ultraviolet light or ozone. The staff finds the applicant's determination that no AMP i s needed acceptable because given that the PVC pipe is encased in concrete, the material will not be exposed to significant ultraviolet light or ozone.
The staff's evaluation for interior concrete of concrete filled steel piles, with no aging effect and
 
no credited AMP and referencing generic note G, is documented in SER Section 3.5.2.3.3.
On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results of material, environment, AERM, and AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.5.2.3.16 Containments, Structures, and Component Supports
-Turbine Building
-Summary of Aging Management Evaluation
-LRA Table 3.5.2-16 The staff reviewed LRA Table 3.5.2-16, which summarizes the results of AMR evaluations for the turbine building component groups.
The staff's evaluation for galvanized, carbon, or low
-alloy steel bolting exposed to outdoor air, which is being managed for loss of preload due to self
-loosening by the Structures Monitoring Program with generic note H, is documented in SER Section 3.5.2.3.6.
The staff's evaluation for aluminum bolting exposed to indoor and outdoor air, which is being managed for loss of preload by the Structures Monitoring Program with generic note H, is documented in SER Section 3.5.2.3.4.
The staff's evaluation for grout penetration seals exposed to an indoor or outdoor air, or groundwater/soil environment, which are being managed for cracking or loss of material by the Structures Monitoring Program with generic note F, is documented in SER Section 3.5.2.3.1.
The staff's evaluation for interior concrete of concrete filled steel piles, with no aging effect and no credited AMP and referencing generic note G, is documented in SER Section 3.5.2.3.3.
3.5.2.3.17 Containments, Structures, and Component Supports-Yard Structures
-Summary of Aging Management Evaluation
-LRA Table 3.5.2-17 The staff reviewed LRA Table 3}}

Latest revision as of 02:12, 14 January 2025

Safety Evaluation Report Related to the License Renewal of Salem Nuclear Generating Station, Units 1 and 2
ML103010100
Person / Time
Site: Salem  PSEG icon.png
Issue date: 11/04/2010
From: Brian Holian
Division of License Renewal
To: Joyce T
Public Service Enterprise Group
CuadradoDeJesus S, NRR/DLR, 415-2946
Shared Package
ML103010097 List:
References
TAC ME1834, TAC ME1836
Download: ML103010100 (749)
v • d • e


Text

Retrieved from "https://kanterella.com/w/index.php?title=ML103010100&oldid=5289831"